¨ | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR | |
x | ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Title of each class | Name of each exchange on which registered |
Common Shares (including Rights under Shareholder Rights Plan) of TransCanada Corporation | New York Stock Exchange |
x Annual information form | x Audited annual financial statements |
Form | Registration No. |
S-8 | 333-5916 |
S-8 | 333-8470 |
S-8 | 333-9130 |
S-8 | 333-151736 |
S-8 | 333-184074 |
S-8 | 333-227114 |
F-3 | 33-13564 |
F-3 | 333-6132 |
F-10 | 333-151781 |
F-10 | 333-161929 |
F-10 | 333-208585 |
F-10 | 333-214971 |
F-10 | 333-218711 |
F-10 | 333-221898 |
F-10 | 333-225941 |
F-10 | 333-228848 |
Chair: Members: | J.E. Lowe S. Crétier S.B. Jackson (as of April 27, 2018) R. Limbacher (as of June 13, 2018) I. Samarasekera T. Vandal |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available, including portfolio management |
• | expected dividend growth |
• | expected future credit ratings |
• | expected costs and schedules for planned projects, including projects under construction and in development |
• | expected capital expenditures and contractual obligations |
• | expected regulatory processes and outcomes, including the impact of recent Federal Energy Regulatory Commission (FERC) policy changes (2018 FERC Actions) |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | the expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
• | regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | anticipated construction costs, schedules and completion dates |
• | access to capital markets, including portfolio management |
• | expected industry, market and economic conditions |
• | inflation rates and commodity prices |
• | interest, tax and foreign exchange rates |
• | nature and scope of hedging. |
• | our ability to successfully implement our strategic priorities and whether they will yield the expected benefits |
• | our ability to implement a capital allocation strategy aligned with maximizing shareholder value |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipeline businesses |
• | the amount of capacity payments and revenues from our energy business due to plant availability |
• | production levels within supply basins |
• | construction and completion of capital projects |
• | costs for labour, equipment and materials |
• | the availability and market prices of commodities |
• | access to capital markets on competitive terms |
• | interest, tax and foreign exchange rates |
• | performance and credit risk of our counterparties |
• | regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims |
• | changes in environmental and other laws and regulations |
• | competition in the pipeline and energy sectors |
• | unexpected or unusual weather |
• | acts of civil disobedience |
• | cyber security and technological developments |
• | economic conditions in North America as well as globally |
• | our ability to effectively anticipate and assess changes to government policies and regulations. |
EXHIBITS | |
13.1 | TransCanada Corporation Annual information form for the year ended December 31, 2018. |
13.2 | Management's discussion and analysis (included on pages 5 through 110 of the TransCanada Corporation 2018 Management's discussion and analysis and audited consolidated financial statements to shareholders). |
13.3 | 2018 Audited consolidated financial statements (included on pages 111 through 190 of the TransCanada Corporation 2018 Management's discussion and analysis and audited consolidated financial statements to shareholders), including the auditors' report thereon and the Report of Independent Registered Public Accounting Firm on the effectiveness of TransCanada's internal control over financial reporting as of December 31, 2018. |
23.1 | Consent of KPMG LLP, Chartered Professional Accountants, Independent Registered Public Accounting Firm. |
31.1 | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.1 | Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements. |
32.2 | Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements. |
101.INS | XBRL Instance Document. |
101.SCH | XBRL Taxonomy Extension Schema Document. |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document. |
101.DEF | XBRL Taxonomy Definition Linkbase Document. |
101.LAB | XBRL Taxonomy Extension Label Linkbase Document. |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document. |
TRANSCANADA CORPORATION | ||
TRANSCANADA PIPELINES LIMITED | ||
(Registrants) | ||
Per: | /s/ DONALD R. MARCHAND | |
DONALD R. MARCHAND Executive Vice-President and Chief Financial Officer | ||
Date: February 14, 2019 |
TransCanada Annual information form 2018 | 2 |
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Health, safety, sustainability and environmental protection and social policies | 19 | |
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Fitch | 25 | |
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TransCanada Annual information form 2018 | 1 |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available, including portfolio management |
• | expected dividend growth |
• | expected future credit ratings |
• | expected costs and schedules for planned projects, including projects under construction and in development |
• | expected capital expenditures and contractual obligations |
• | expected regulatory processes and outcomes, including the impact of recent Federal Energy Regulatory Commission (FERC) policy changes (2018 FERC Actions) |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | the expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
2 | TransCanada Annual information form 2018 |
• | regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | anticipated construction costs, schedules and completion dates |
• | access to capital markets, including portfolio management |
• | expected industry, market and economic conditions |
• | inflation rates and commodity prices |
• | interest, tax and foreign exchange rates |
• | nature and scope of hedging. |
• | our ability to successfully implement our strategic priorities and whether they will yield the expected benefits |
• | our ability to implement a capital allocation strategy aligned with maximizing shareholder value |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipeline businesses |
• | the amount of capacity payments and revenues from our energy business due to plant availability |
• | production levels within supply basins |
• | construction and completion of capital projects |
• | costs for labour, equipment and materials |
• | the availability and market prices of commodities |
• | access to capital markets on competitive terms |
• | interest, tax and foreign exchange rates |
• | performance and credit risk of our counterparties |
• | regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims |
• | changes in environmental and other laws and regulations |
• | competition in the pipeline and energy sectors |
• | unexpected or unusual weather |
• | acts of civil disobedience |
• | cyber security and technological developments |
• | economic conditions in North America as well as globally |
• | our ability to effectively anticipate and assess changes to government policies and regulations. |
TransCanada Annual information form 2018 | 3 |
TransCanada Corporation Canada TransCanada PipeLines Limited Canada TransCanada PipeLine USA Ltd. Nevada TransCanada Oil Pipelines Inc. Delaware TransCanada Keystone Pipeline, LP Delaware Columbia Pipeline Group, Inc. Delaware Columbia Energy Group Delaware CPG OpCo LP Delaware Columbia Gas Transmission, LLC Delaware NOVA Gas Transmission Ltd. Alberta |
4 | TransCanada Annual information form 2018 |
Date | Description of development |
CANADIAN REGULATED PIPELINES | |
NGTL System - Expansion Programs | |
2016 | In 2016, we had approximately $2.3 billion of facilities that received regulatory approval and approximately $0.45 billion under construction. In October 2016, the Government of Canada approved our application for a $1.3 billion NGTL System expansion program. This NGTL System expansion program consists of five pipeline loops ranging in size from 24 to 48-inch pipe of approximately 230 km (143 miles) in length, and two compressor station unit additions of approximately 46.5 MW (62,360 hp). In 2016, we placed approximately $0.5 billion of new facilities in service. |
2017 | In June 2017, we announced a $2.0 billion expansion program on our NGTL System based on contracted customer demand for approximately 3.2 PJ/d (3 Bcf/d) of incremental firm receipt and delivery services, subject to regulatory approvals. Construction is expected to start in early 2019, with initial projects expected to be in service in fourth quarter 2019 and final projects in service in 2021. In 2017, we placed approximately $1.7 billion of new facilities in service. |
2018 | In February 2018, we announced the NGTL System 2021 Expansion Program with an estimated capital cost of $2.3 billion and an anticipated in-service date in the first half of 2021. This program consists of approximately 375 km (233 miles) of new pipeline, three compressor units, a control valve and associated facilities. The expansion is required to connect incremental supply and expand basin export capacity by 1.1 PJ/d (1 Bcf/d) to the Empress export delivery point at the interconnection of the NGTL System and the Canadian Mainline. An application to construct and operate the NGTL System 2021 Expansion Program was filed with the NEB in June 2018 and will proceed through a public hearing in third quarter 2019. In October 2018, we announced the NGTL System 2022 Expansion Program to meet capacity requirements for incremental firm receipt and intra-basin delivery services to commence in November 2021 and April 2022. This $1.5 billion expansion of the NGTL System consists of approximately 197 km (122 miles) of new pipeline, three compressor units, meter stations and associated facilities. Applications for approvals to construct and operate the facilities are expected to be filed with the NEB in second quarter 2019 and, pending receipt of regulatory approvals, construction would start as early as third quarter 2020. In 2018, we placed approximately $0.6 billion of projects in service. |
NGTL System - North Montney Mainline (NMML) | |
2016 | In September 2016, the Government of Canada approved a sunset clause extension request that we filed in March 2016, for the NMML Certificate of Public Convenience and Necessity (CPCN), for one year to June 10, 2017. |
2017 | In March 2017, we filed an application with the NEB for a variance to the existing approvals for the NMML project to remove the condition that the project could only proceed once a positive FID was made for the Pacific Northwest LNG project. The NMML project consists of approximately 206 km (128 miles) of new pipeline, three compressor units and 14 meter stations. The NMML project is underpinned by restructured 20-year commercial contracts with shippers and is not dependent on the Pacific Northwest LNG project proceeding. |
TransCanada Annual information form 2018 | 5 |
Date | Description of development |
2018 | In July 2018, the NEB issued an amending order and amended CPCN following the Government of Canada approval of our application, to the existing NMML project approvals to remove the condition requiring a positive FID for the Pacific Northwest LNG project prior to commencement of construction. The NEB directed NGTL to seek approval for a revised tolling methodology for the project following a provisional period defined as one year after the receipt of the Government of Canada decision, otherwise stand-alone tolling will be imposed as a default. NGTL is working with its shippers to address this requirement and is confident an acceptable tolling mechanism, other than stand-alone tolling, will be established. Construction on the NMML project was initiated in August 2018. The first phase of the project is anticipated to be in service by fourth quarter 2019, and the second phase by second quarter 2020. The current estimated project cost increased from original estimates by $0.2 billion to $1.6 billion mainly due to construction schedule delays and an increase in market-dependent construction costs. |
NGTL System - Revenue Requirement Settlements | |
2017 | The two-year revenue requirement agreement for 2016-2017 Settlement expired on December 31, 2017. The 2016-2017 Settlement fixed ROE at 10.1 per cent on 40 per cent deemed common equity, established depreciation at a forecast composite rate of 3.16 per cent and fixed OM&A costs at $222.5 million annually. An incentive mechanism for variances enabled NGTL to capture savings from improved performance and provided for the flow-through of all other costs, including pipeline integrity expenses and emissions costs. On November 24, 2017, the NEB approved interim tolls for 2018. |
2018 | In June 2018, the NEB approved the 2018-2019 Revenue Requirement Settlement (2018-2019 Settlement), as filed, and the resulting final 2018 tolls. The 2018-2019 Settlement, which is effective from January 1, 2018 to December 31, 2019, fixes ROE at 10.1 per cent on 40 per cent deemed common equity and increases the composite depreciation rate from 3.18 per cent to 3.45 per cent. OM&A costs are fixed at $225 million for 2018 and $230 million for 2019 with a 50/50 sharing mechanism for any variances between the fixed amounts and actual OM&A costs. All other costs, including pipeline integrity expenses and emissions costs, are treated as flow-through expenses. |
Canadian Mainline – Eastern Mainline Project | |
2016 | The Eastern Mainline project was conditioned on the approval and construction of the Energy East pipeline. Refer to the General development of the business – Liquids Pipelines section for information on Energy East. |
2017 | In October 2017, after a careful review of the changed circumstances, we informed the NEB that we would not be proceeding with the Energy East and Eastern Mainline project applications, that in effect provided public notice that the projects were canceled. Refer to the General development of the business – Liquids Pipelines section for information on Energy East. |
Canadian Mainline - Long-Term Fixed-Price (LTFP) Services | |
2017 | In November 2017, we began offering a new NEB-approved service on the Canadian Mainline referred to as the Dawn LTFP service. This service enables WCSB producers to transport up to 1.5 PJ/d (1.4 Bcf/d) of natural gas at a simplified toll of $0.77/GJ from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The LTFP service is underpinned by ten-year contracts that have early termination rights after five years. Any early termination will result in an increased toll for the last two years of the contract. |
2018 | In December 2018, we announced 670 TJ/d (625 MMcf/d) of new natural gas transportation contracts from the WCSB on the Canadian Mainline. Upon NEB approval of this LTFP service, referred to as the North Bay Junction (NBJ) LTFP service, incremental volumes under these LTFP contracts will reach markets in Ontario, Québec, New Brunswick, Nova Scotia and the Northeastern U.S. using existing capacity on the Canadian Mainline as well as new compression facilities. Customers have executed 15-year precedent agreements to proceed with the project with an estimated capital cost of $96 million. |
2019 | In January 2019, we filed an application for approval of the NBJ LTFP with the NEB, and expect a decision in third quarter 2019. |
Canadian Mainline Settlement | |
2017 | While the NEB-approved Canadian Mainline's 2015-2030 tolls and tariff settlement (LDC Settlement) specified tolls for 2015-2020, the NEB ordered a toll review halfway through this six-year period. A supplemental agreement for the 2018-2020 period was executed between TransCanada and eastern LDCs and filed with the NEB in December 2017 (Supplemental Agreement). The Supplemental Agreement, supported by a majority of Canadian Mainline stakeholders, proposed lower tolls, preserved an incentive arrangement that provides an opportunity for 10.1 per cent, or greater return, on a 40 per cent deemed common equity and described the revenue requirements and billing determinants for the 2018-2020 period. Interim tolls for 2018, as established by the Supplemental Agreement, were filed and subsequently approved by the NEB in December 2017. |
2018 | In October 2018, we concluded the written hearing process for the Canadian Mainline 2018-2020 toll review with the filing of our reply evidence to the NEB. In December 2018, the NEB 2018 decision was issued (NEB 2018 Decision), approving all elements of the application, including our cost and volume forecasts, higher depreciation rates and continuation of pricing discretion, with the exception of the amortization period for the Long Term Adjustment Account (LTAA), which is now to be amortized over 2018 to 2020. The impact of the NEB 2018 Decision was reflected in lower tolls effective February 1, 2019. |
2019 | As directed by the NEB, we filed a compliance filing in January 2019, the outcome of which is expected in first quarter 2019. |
6 | TransCanada Annual information form 2018 |
Date | Description of development |
LNG PIPELINE PROJECTS | |
Prince Rupert Gas Transmission (PRGT) | |
2016 | In September 2016, PNW LNG received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. In December 2016, PNW LNG received an LNG export license from the NEB which extended the export term from 25 years to 40 years. We continued our engagement with Indigenous groups and signed project agreements with 14 First Nation groups along the pipeline route, which outlined financial and other benefits and commitments that would be provided to each First Nation for as long as the project was in service. |
2017 | In July 2017, we were notified that PNW LNG would not be proceeding with their proposed LNG project and that Progress Energy would be terminating their agreement with us for development of the PRGT project. In accordance with the terms of the agreement, we received a payment of $0.6 billion from Progress Energy in October 2017 for full recovery of our costs plus carrying charges. |
Coastal GasLink | |
2016 | In first quarter 2016, we continued to engage with Indigenous groups and announced project agreements with 11 First Nation groups along the pipeline route, which outlined financial and other benefits and commitments that would be provided to each First Nation group for as long as the project was in service. We also continued to engage with stakeholders along the pipeline route and progressed detailed engineering and construction planning work to refine the capital cost estimate. In response to feedback received, we applied for a minor route amendment to the BCEAO in order to provide an option in the area of concern. In July 2016, the LNG Canada joint venture participants announced a delay to their FID for the proposed facility in Kitimat, B.C. We worked with LNG Canada to maintain the appropriate pace of the Coastal GasLink development schedule and work activities. We continued our engagement with Indigenous groups along our pipeline route and concluded long-term project agreements with 17 First Nation communities. |
2017 | The continuing delay in the FID for the LNG Canada project triggered a restructuring of the provisions in the Coastal GasLink project agreement with LNG Canada that resulted in the payment of certain amounts to TransCanada with respect to carrying charges on costs incurred. In 2017, we received payments of $88 million related to carrying charges on costs incurred since inception of the project. Coastal GasLink filed an amendment to the Environmental Assessment Certificate in November 2017 for an alternate route on a portion of the pipeline. |
2018 | In October 2018, we announced that we are proceeding with construction of the Coastal GasLink pipeline project following the LNG Canada joint venture participants' announcement that they had reached a positive FID to build the LNG Canada natural gas liquefaction facility in Kitimat, B.C. Coastal GasLink will provide the natural gas supply to the LNG Canada facility and is underpinned by 25-year TSAs (with additional renewal provisions) with each of the five LNG Canada participants. Coastal GasLink will be a 670 km (416 miles) pipeline with an initial capacity of approximately 2.2 PJ/d (2.1 Bcf/d) with potential expansion capacity up to 5.4 PJ/d (5.0 Bcf/d). All necessary regulatory permits have been received to allow us to proceed with construction activities which began in December 2018, with a planned in-service date in 2023. Coastal GasLink has signed project and community agreements with all 20 elected Indigenous bands along the pipeline route, confirming strong support from Indigenous communities across the province of B.C. In July 2018, an individual asked the NEB to consider whether the Coastal GasLink pipeline should be federally regulated by the NEB. In October 2018, the NEB advised that it would consider the question of jurisdiction, granted Coastal GasLink standing in the matter, and reserved the right to decide on the participation of all other potentially interested parties, including the individual who raised the question. In December 2018, the NEB issued a process letter addressing participation and set the schedule which is expected to conclude in the second half of 2019, with a decision to follow. In December 2018, the B.C. Supreme Court issued an interim injunction, ordering opponents of the Coastal GasLink project to allow pipeline construction workers access to a blockaded area of the Coastal GasLink right of way, south of Houston, B.C. The Coastal GasLink capital cost estimate is $6.2 billion with the majority of the construction spend occurring in 2020 and 2021. Subject to terms and conditions, differences between the estimated capital cost and final cost of the project will be recovered in future pipeline tolls. As part of the Coastal GasLink funding plan, we are exploring joint venture partners and project financing. The total capital cost includes pre-FID costs incurred of $470 million. In accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to reimburse us for their share of pre-FID costs, totaling $470 million, in November 2018. In addition, all five LNG Canada joint venture participants elected to make cash payments throughout the construction period with respect to carrying charges on costs incurred. |
2019 | In January 2019, the RCMP moved to enforce the injunction issued by the B.C. Supreme Court. Following negotiations, the blockaders agreed to abide by the terms of the injunction and allow access to the area. |
TransCanada Annual information form 2018 | 7 |
Date | Description of development |
U.S. NATURAL GAS PIPELINES - COLUMBIA | |
Columbia Acquisition | |
2016 | On July 1, 2016, we acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016, through a public offering, and following the closing of the acquisition, the subscription receipts were exchanged into 96.6 million TransCanada common shares. |
Columbia Pipeline Partners LP (CPPL) | |
2016 | In November 2016, we announced that we entered into an agreement and plan of merger through which Columbia agreed to acquire, for cash, all of the outstanding publicly held common units of CPPL. |
2017 | In February 2017, we completed the acquisition, for cash, of all outstanding publicly held common units of CPPL at a price of US$17.00 and a stub period distribution of US$0.10 per common unit for an aggregate transaction value of US$921 million. |
Columbia Gas - Leach XPress | |
2016 | The FEIS for the Leach XPress project was received in September 2016. The project transports approximately 1.6 PJ/d (1.5 Bcf/d) of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with Columbia Gulf, and consists of 260 km (160 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30-inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression. |
2018 | The US$1.6 billion project was placed in service in January 2018. |
Columbia Gas - Mountaineer XPress | |
2016 | The FERC 7(C) application for the Mountaineer XPress project was filed in April 2016. The project is designed to transport supply from the Marcellus and Utica shale plays to points along the system and to the Leach interconnect with Columbia Gulf. The project consists of 275 km (171 miles) of 36-inch greenfield pipeline, ten km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression. |
2017 | The FERC certificate for the Mountaineer XPress project was received in December 2017. |
2019 | Approximately 45 per cent of the Mountaineer XPress project was placed in service in January 2019, with the remainder to be placed in service in February and March 2019, along with Gulf Xpress (see Columbia Gulf - Gulf XPress below). Total estimated project costs have been revised upwards to US$3.2 billion reflecting the impact of delays of various regulatory approvals from the FERC and other agencies, increased contractor construction costs due to unusually high demand for construction resources in the region, unusually high instances of inclement weather throughout construction, and modifications to contractor work plans to mitigate construction delays associated with these impacts. |
Columbia Gas - WB XPress | |
2017 | The FERC certificate for the WB XPress project was received in November 2017. |
2018 | The WB XPress project, designed to transport approximately 1.4 PJ/d (1.3 Bcf/d) of Marcellus gas supply westbound to the Gulf Coast and eastbound to Mid-Atlantic markets, was placed in service in October 2018 and November 2018 for the Western Build and Eastern Build, respectively. |
Columbia Gas - Buckeye XPress | |
2017 | The Buckeye XPress project represents an upsizing of an existing pipeline replacement project in conjunction with our Columbia Gas modernization program. The US$0.2 billion cost to upsize the replacement pipe and install compressor upgrades will enable us to offer approximately 290 TJ/d (275 MMcf/d) of incremental pipeline capacity to accommodate growing Appalachian production. We expect the project to be placed in service in late-2020. |
Columbia Gulf - Rayne XPress | |
2016 | The FEIS for the Rayne XPress project was received in September 2016. The project transports approximately 1.1 PJ/d (1 Bcf/d) of supply from an interconnect with the Leach XPress pipeline project and another interconnect, to markets along the system and to the Gulf Coast. The project consists of bi-directional compressor station modifications along Columbia Gulf, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement. |
2017 | The US$0.4 billion project was placed in service in November 2017. |
8 | TransCanada Annual information form 2018 |
Date | Description of development |
Columbia Gulf - Gulf XPress | |
2016 | The FERC 7(C) application for the Gulf XPress project was filed in April 2016. The project is associated with the Mountaineer XPress expansion to move Appalachian supply to the Gulf Coast by the addition of seven greenfield mid-point compressor stations along the Columbia Gulf route. |
2017 | The FERC certificate for the Gulf XPress project was received on December 29, 2017. |
2019 | The US$0.6 billion project is expected to be placed in service in February and March 2019. |
Columbia Gulf - Cameron Access | |
2018 | The Cameron Access project, designed to transport approximately 0.9 PJ/d (0.8 Bcf/d) of gas supply to the Cameron LNG export terminal in Louisiana, was placed in service in March 2018. |
Columbia Gulf - Louisiana XPress | |
2018 | In November 2018, we sanctioned the Louisiana XPress project which will connect supply directly to Gulf Coast LNG export markets with the addition of three greenfield mid-point compressor stations along Columbia Gulf. The estimated US$0.4 billion project is expected to be placed in service in 2022. |
Modernization I & II | |
2017 | Columbia Gas and its customers entered into a settlement arrangement, approved by the FERC, which provides recovery and return on investment to modernize its system, improve system integrity, and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities, and improvements in control systems. The US$1.5 billion Modernization I arrangement was completed under the terms of a 2012 settlement agreement, with the final US$0.2 billion spent in 2017. Modernization II has been approved for up to US$1.1 billion of work starting in 2018 and to be completed through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year. |
OTHER U.S. NATURAL GAS PIPELINES | |
ANR Pipeline | |
2016 | ANR Pipeline filed a Section 4 Rate Case that requested an increase to ANR's maximum transportation rates in January 2016. Shifts in ANR’s traditional supply sources and markets, necessary operational changes, needed infrastructure updates, and evolving regulatory requirements were driving required investment in facility maintenance, reliability and system integrity as well as an increase in operating costs that resulted in the current tariff rates not providing a reasonable return on our investment. We also pursued a collaborative process to find a mutually beneficial outcome with our customers through settlement negotiations. ANR's last rate case filing was more than 20 years ago. ANR reached a settlement with its shippers effective August 1, 2016 and received FERC approval on December 16, 2016. Per the settlement, transmission reservation rates would increase by 34.8 per cent and storage rates would remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022. |
Great Lakes | |
2017 | In October 2017, Great Lakes filed a rate settlement with the FERC to satisfy its obligations from its previous 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Rate Settlement). In conjunction with the Canadian Mainline's LTFP service (see Canadian Regulated Pipelines – Long-Term Fixed-Price Service above), Great Lakes entered into a new ten-year gas transportation contract with the Canadian Mainline. This NEB-approved contract, effective November 1, 2017, contains volume reduction options up to full contract quantity beginning in year three. |
Portland Natural Gas Transmission System (Portland) | |
2016 | In January 2016, we closed the sale of our 49.9 per cent of our total 61.7 per cent interest in Portland to TC PipeLines, LP (TCLP) for US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million of a proportionate share of Portland debt. |
2017 | In June 2017, we closed the sale of a 49.34 per cent of our 50 per cent interest in Iroquois, along with an option to sell the remaining 0.66 per cent at a later date, to TCLP. At the same time, we closed the sale of our remaining 11.81 per cent interest in Portland to TCLP. Proceeds from these transactions were US$765 million, before post-closing adjustments, and were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and Portland debt. In December 2017, Portland executed precedent agreements with several LDCs in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019, as well as expand the Portland system to bring its certificated capacity from 222 TJ/d (210 MMcf/d) up to 290 TJ/d (275 MMcf/d). The approximate US$80 million Portland XPress Project will proceed concurrently with upstream capacity expansions. The in-service dates of the Portland XPress project are being phased-in over a three-year period, beginning November 1, 2018. |
2018 | Phase I of Portland XPress was placed in service on November 1, 2018. |
TransCanada Annual information form 2018 | 9 |
Date | Description of development |
Iroquois Gas Transmission System, L.P. (Iroquois) | |
2016 | FERC approvals were obtained for settlements with shippers for our Iroquois, Tuscarora and Columbia Gulf pipelines in third quarter 2016. In March 2016, we acquired an additional 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million and in May 2016, a further 0.65 per cent was acquired for US$7 million. As a result, our interest in Iroquois increased to 50 per cent. |
2017 | In June 2017, we closed the sale of a 49.34 per cent of our 50 per cent interest in Iroquois, along with an option to sell the remaining 0.66 per cent at a later date, to TCLP. At the same time, we closed the sale of our remaining 11.81 per cent interest in Portland to TCLP. Refer to the Portland Natural Gas Transmission System section above. |
Date | Description of development |
MEXICO NATURAL GAS PIPELINES | |
Topolobampo | |
2016 | In November 2012, we were awarded the contract to build, own and operate the Topolobampo project. Construction on the project is supported by a 25-year TSA for 720 TJ/d (670 MMcf/d) with the CFE. The Topolobampo project is a 560 km (348 miles), 30-inch pipeline that will receive gas from the upstream pipelines near El Encino, Chihuahua, and will deliver natural gas from these interconnecting pipelines to delivery points along the pipeline route including our Mazatlán pipeline at El Oro, Sinaloa. |
2017 | The Topolobampo project was substantially complete, excluding a 20 km (12 miles) section due to delays experienced by the Secretary of Energy, the government department which conducts indigenous consultations in Mexico. Under the terms of the TSA, the delays were recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016. The pipeline cost is approximately US$1.2 billion, an increase of US$0.2 billion from the original estimate, due to the delays. |
2018 | The Topolobampo project was placed in service in June 2018. |
Mazatlán | |
2016 | In November 2012 we were awarded the contract to build, own and operate the Mazatlán project. This project is a 430 km (267 miles), 24-inch pipeline running from El Oro to Mazatlán, Sinaloa, with an estimated cost of US$0.4 billion. This pipeline is supported by a 25-year natural gas TSA for 214 TJ/d (200 MMcf/d) with the CFE. Physical construction was completed in 2016 and was awaiting natural gas supply from upstream interconnecting pipelines. We met our obligations and collected revenue as per provisions in the contract and per the original TSA service commencement date of December 2016. |
2017 | The Mazatlán project was placed into full service in July 2017. |
Tula | |
2016 | In November 2015, we were awarded the contract to build, own and operate the 36-inch, 324 km (201 miles) pipeline with a 16-inch, 24 km (15 miles) lateral, supported by a 25-year natural gas TSA for 949 TJ/d (886 MMcf/d) with the CFE. The pipeline will transport natural gas from Tuxpan, Veracruz to markets near Tula, extending through the states of Puebla and Hidalgo. |
2017 | Construction of the Tula pipeline was substantially completed in 2017, with the exception of approximately 90 km (56 miles) of the pipeline. |
2018 | The CFE has approved the recognition of force majeure events for the Tula pipeline, including the continuation of the payment of fixed capacity charges to us that began in first quarter 2018. Commencement of constructing the central segment of the project has been delayed due to a lack of progress by the Secretary of Energy, the governmental department responsible for indigenous consultation. Project completion has been revised to the end of 2020. We have negotiated separate CFE contracts that would allow certain segments of the pipeline to be placed in service when gas is available. |
Villa de Reyes | |
2016 | In April 2016, we were awarded the contract to build, own and operate the 36- and 24-inch Villa de Reyes pipelines, totaling 420 km (261 miles). Construction of the pipeline is supported by a 25-year natural gas TSA for 949 TJ/d (886 MMcf/d) with the CFE. The bi-directional pipeline will transport natural gas from Tula, Hidalgo to Villa de Reyes, San Luis Potosí, connecting to the Tamazunchale and Tula pipelines including a lateral to the Salamanca industrial complex in Guanajuato. |
2017 | Construction of the project commenced, however, delays due to archeological investigations by state authorities caused the in-service date to be revised to the second half of 2019. |
2018 | The CFE has approved the recognition of force majeure events for the Villa de Reyes pipeline, including the continuation of the payment of fixed capacity charges to us that began in first quarter 2018. Construction for the project is ongoing and is anticipated to be in service in the second half of 2019. We have negotiated separate CFE contracts that would allow certain segments of the pipeline to be placed in service when gas is available. |
10 | TransCanada Annual information form 2018 |
Date | Description of development |
Sur de Texas | |
2016 | The Sur de Texas project is a joint venture with IEnova in which we hold a 60 per cent interest representing an investment of approximately US$1.3 billion. Construction of the pipeline is supported by a 25-year natural gas TSA for 2.8 PJ/d (2.6 Bcf/d) with the CFE. The 42-inch, 775 km (482 miles) pipeline will begin offshore in the Gulf of Mexico, at the border near Brownsville, Texas, and end in Tuxpan, Veracruz. The project will deliver natural gas to our Tamazunchale and Tula pipelines and to other third-party facilities. |
2017 | Approximately 60 per cent of the off-shore construction completed at December 31, 2017. |
2018 | Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date in early second quarter 2019. An amending agreement was signed with the CFE that recognizes force majeure events and the commencement of payments of fixed capacity charges began on October 31, 2018. |
TransCanada Annual information form 2018 | 11 |
Date | Description of development |
Keystone Pipeline System | |
2016 | The Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline to Houston, Texas, went into service in August 2016. The terminal has an initial storage capacity for 700,000 barrels of crude oil. The HoustonLink pipeline which connects the Houston Terminal to Magellan's Houston and Texas City, Texas delivery system was completed in December 2016. The CITGO Petroleum (CITGO) Sour Lake pipeline connection between the Keystone Pipeline and CITGO's Sour Lake, Texas terminal was placed in service in December 2016. |
2017 | In fourth quarter 2017, we concluded open seasons for the Keystone pipeline and Marketlink and secured incremental long-term contractual support. In November 2017, the Keystone pipeline was temporarily shut down after a leak was detected in Marshall County, South Dakota. The estimated volume of the release was 5,000 barrels as reported to the NRC and the PHMSA. On November 29, 2017, the pipeline was repaired and returned to service at a reduced pressure in the affected section of the pipeline. This shutdown did not have a significant impact on our 2017 earnings. |
2018 | In 2018, we concluded successful open seasons for Marketlink securing incremental contractual support. We continue to expand our terminal facilities which are integral to our operations, with the completion of an additional one million barrels of storage at Cushing, Oklahoma. |
Keystone XL | |
2016 | In January 2016, the South Dakota PUC accepted Keystone XL's certification that it continued to comply with the conditions in its existing 2010 permit authority in the state. In January 2016, we filed a Notice of Intent to initiate a claim under Chapter 11 of NAFTA in response to the U.S. Administration’s decision to deny a Presidential permit for the Keystone XL Pipeline on the basis that the denial was arbitrary and unjustified. Through the NAFTA claim, we were seeking to recover more than US$15 billion in costs and damages that we estimated to have suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. In June 2016, we filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of NAFTA. In January 2016, we also filed a lawsuit in the U.S. Federal Court in Houston, Texas, asserting that the U.S. President’s decision to deny construction of Keystone XL exceeded his power under the U.S. Constitution. The federal court lawsuit did not seek damages, but rather a declaration that the permit denial was without legal merit and that no further Presidential action was required before construction of the pipeline could proceed. |
2017 | In January 2017, the U.S. President signed a Presidential Memorandum inviting TransCanada to refile an application for the U.S. Presidential Permit (Presidential Permit), which we later filed with the DOS. In February 2017, we filed an application with the Nebraska PSC to seek approval for the Keystone XL pipeline route through the state. In March 2017, the DOS issued a Presidential Permit authorizing construction of the U.S./ Canada border crossing facilities of Keystone XL. We discontinued our claim under Chapter 11 of NAFTA and withdrew the U.S. Constitutional challenge. In March 2017, two lawsuits were filed in Montana District Court challenging the validity of the Presidential Permit. Along with the U.S. Government, we filed motions for dismissal of these lawsuits which were subsequently denied in November 2017. The cases will now proceed to the consideration of summary judgment motions. In July 2017, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on the Keystone pipeline and for Keystone XL from Hardisty, Alberta to Cushing, Oklahoma and the U.S. Gulf Coast, which concluded in October 2017. In November 2017, we received PSC approval for the alternative mainline route and we filed a motion with the PSC to reconsider its ruling and permit us to file an amended application that would support their decision and would address certain issues related to their selection of the alternative route, which was denied in December 2017. In December 2017, opponents of Keystone XL and intervenors in the Nebraska regulatory proceeding filed an appeal of the PSC decision seeking to have that decision overturned. TransCanada supports the decision of the PSC and will actively participate in the appeal process to defend that decision. |
2018 | We have secured commercial support for all available Keystone XL project capacity and commenced certain pre-construction activities. The Nebraska Supreme Court agreed to hear an appeal of the Nebraska PSC route approval, in which oral arguments were heard in November 2018. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by first quarter 2019. The Presidential Permit was challenged in two separate lawsuits commenced in Montana. Together with the DOJ, we are actively participating in these lawsuits to defend both the issuance of the Presidential Permit and the exhaustive environmental assessments that support the U.S. President's actions. Legal arguments addressing the merits of these lawsuits were heard in second quarter 2018. In third quarter 2018, the U.S. District Court in Montana issued a Partial Order requiring the DOJ and the DOS (collectively, the Federal Defendants) to prepare a supplemental environmental impact statement (SEIS) to the 2014 Final SEIS. In fourth quarter 2018, the U.S. District Court Judge in Montana invalidated the Presidential Permit and granted a partial injunction on the Keystone XL project. We applied to the U.S. District Court for a stay of its various decisions affecting the issuance of the Presidential Permit and the extensive environmental assessments that have been done in support of its issuance.That stay application was heard on January 14, 2019 and we are awaiting a decision. We intend to further pursue a stay of these decisions with the Ninth Circuit Court of Appeals. Our plans to commence construction of the Keystone XL project in 2019 will be impacted by the timing and |
12 | TransCanada Annual information form 2018 |
Date | Description of development |
2018 (continued) | outcome of our appeal and stay proceedings. In September 2018, two U.S. Native American communities filed a lawsuit in Montana challenging the Presidential Permit. We have been granted intervenor status in the lawsuits. Initial briefing dates have been established, but no further action has occurred. The South Dakota PUC permit for the Keystone XL project was issued in June 2010 and certified in January 2016. An appeal of that certification was denied in June 2017 and that decision was further appealed to the South Dakota Supreme Court. In June 2018, the Supreme Court dismissed the appeal against the certification of the Keystone XL project finding that the lower court lacked jurisdiction to hear the case. This decision is final as there can be no further appeals from this decision by the Supreme Court. |
Energy East | |
2016 | In May 2016, we filed a consolidated application with the NEB for the Energy East pipeline. In June 2016, Energy East achieved a major milestone with the NEB’s announcement determining the Energy East pipeline application was sufficiently complete to initiate the formal regulatory review process. However, in August 2016, panel sessions were canceled as three NEB panelists recused themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. As a result, all hearings for the project were adjourned until further notice. |
2017 | In January 2017, the NEB appointed three new permanent panel members to undertake the review of the Energy East and Eastern Mainline projects, and subsequently voided all decisions made by the previous hearing panel members and removing such decisions from the official hearing record. We were not required to refile the application and parties were not required to reapply for intervener status. In September 2017, we requested the NEB suspend the review of the Energy East and Eastern Mainline project applications for 30 days to provide time for us to conduct a careful review of the NEB's changes, which were announced in August 2017. In October 2017, after careful review of the changed circumstances, we informed the NEB that we would not be proceeding with the Energy East and Eastern Mainline project applications. We also notified the MDDELCC that we were withdrawing the Energy East project from the environmental review process. As the Energy East pipeline was also to provide transportation services for the Upland pipeline, the DOS was notified in October 2017, that we would no longer be pursuing the U.S. Presidential Permit application for that project. We reviewed the $1.3 billion carrying value of the projects, including AFUDC capitalized since inception, and recorded a $954 million after-tax impairment charge in our fourth quarter 2017 results. We ceased capitalizing AFUDC on the projects effective August 23, 2017, the date of the NEB's announced scope changes. With Energy East's inability to reach a regulatory decision, no recoveries of costs from third parties are forthcoming. |
Grand Rapids | |
2016 | Construction continued on the Grand Rapids pipeline. We entered into a partnership with Brion Energy Corporation (Brion) to develop Grand Rapids with each party owning 50 per cent of the pipeline project. Our partner has also entered into a long-term transportation service contract in support of the project. Construction progressed on the 20-inch diluent joint venture pipeline between Edmonton and Fort Saskatchewan, Alberta. The joint venture between Grand Rapids and Keyera was incorporated into Grand Rapids to provide enhanced diluent supply alternatives to our shippers. |
2017 | In August 2017, the Grand Rapids pipeline, jointly owned by TransCanada and PetroChina Canada Ltd. (formerly Brion), was placed in service. The 460 km (287 miles) crude oil transportation system connects producing area northwest of Fort McMurray, Alberta to terminals in the Heartland, Alberta market region. |
Northern Courier | |
2016 | Construction continued on the Northern Courier pipeline, a 90 km (56 miles) pipeline system that transports bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta. The project is fully underpinned by long-term contracts with the Fort Hills partnership. |
2017 | The Northern Courier pipeline achieved commercial in-service in November 2017. |
White Spruce | |
2016 | In December 2016, we finalized a long-term transportation agreement to develop and construct the 20-inch, 72 km (45 miles) White Spruce pipeline, which would transport crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta to the Grand Rapids pipeline. |
2018 | In February 2018, the AER issued a permit for the construction of the $200 million White Spruce pipeline. Construction has commenced with an anticipated in-service date in second quarter 2019. |
TransCanada Annual information form 2018 | 13 |
Date | Description of development |
CANADIAN POWER | |
Alberta PPAs | |
2016 | In March 2016, we issued notice to the Balancing Pool to terminate our Alberta PPAs. In July 2016, we, along with the ASTC Power Partnership (ASTC), issued a notice referring the matter to be resolved by binding arbitration pursuant to the dispute resolution provisions of the PPAs. On July 25, 2016, the Government of Alberta brought an application in the Court of Queen’s Bench to prevent the Balancing Pool from allowing termination of a PPA held by another party which contains identically worded termination provisions to our PPAs. In December 2016, management engaged in settlement negotiations with the Government of Alberta and finalized terms of the settlement of all legal disputes related to the PPA terminations. The Government of Alberta and the Balancing Pool agreed to our termination of the PPAs resulting in the transfer of all our obligations under such PPAs to the Balancing Pool. Upon final settlement of the PPA terminations, we transferred to the Balancing Pool a package of environmental credits held to offset the PPA emissions costs and recorded a non-cash charge of $92 million before-tax ($68 million after-tax) related to the carrying value of our environmental credits. In first quarter 2016, as a result of our decision to terminate the PPAs, we recorded a non-cash impairment charge of $240 million before-tax ($176 million after-tax) comprised of $211 million before-tax ($155 million after-tax) related to the carrying value of our Sundance A and Sheerness PPAs and $29 million before-tax ($21 million after-tax) on our equity investment in the ASTC which previously held the Sundance B PPA. |
Napanee | |
2018 | Construction is substantially complete and commissioning activities are continuing at our 900 MW natural gas-fired power plant at Ontario Power Generation's Lennox site in eastern Ontario, in the town of Greater Napanee. We expect our total investment in the Napanee facility will be approximately $1.7 billion, with commercial operations expected to begin in second quarter 2019. |
Cartier Wind | |
2018 | In October 2018, we completed the sale of our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for net proceeds of approximately $630 million, before post-closing adjustments, resulting in a gain of $170 million ($143 million after-tax). |
Bécancour | |
2016 | In 2015, we executed an agreement with Hydro-Québec Distribution (HQ) allowing HQ to dispatch up to 570 MW of peak winter capacity from our Bécancour facility for a term of 20 years commencing in December 2016. The regulator in Québec, Régie de l'énergie, reversed its initial decision to approve this agreement. In November 2016, HQ released a new ten-year supply plan indicating additional peak winter capacity from Bécancour was not required. Management does not expect further developments at Bécancour until November 2019 when the next ten-year supply plan is filed. |
Bruce Power | |
2016 | Bruce Power entered into an agreement with the IESO in 2015 to extend the operating life of the facility to the end of 2064. This new agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site. The amended agreement, which took effect on January 1, 2016, allows Bruce Power to immediately invest in life extension activities for Units 3 through 8. Beginning in January 2016, Bruce Power received a uniform price of $65.73 per MWh for all units, which included certain flow-through items such as fuel and lease expense recovery. Over time, the uniform price is subject to adjustments for the return of and on capital invested at Bruce Power under the asset management (AM) and major component replacement (MCR) programs, along with various other pricing adjustments that would allow for a better matching of revenues and costs over the long-term. In connection with this opportunity, we exercised our option to acquire an additional 14.89 per cent ownership interest in Bruce B for $236 million from the Ontario Municipal Employees Retirement System. Subsequent to this acquisition, Bruce A and Bruce B were merged to form a single partnership structure, of which we hold a 48.4 per cent interest. |
2018 | In September 2018, Bruce Power submitted its final cost and schedule duration estimate (basis of estimate) for the Unit 6 MCR program to the IESO. The IESO has verified the basis of estimate and the Unit 6 MCR program is scheduled to begin in early-2020 with an expected completion in late-2023. Our project cost estimates reflect our expected investment of approximately $2.2 billion (in nominal dollars) in Bruce Power's Unit 6 MCR program and its ongoing AM program through 2023 as well as approximately $6.0 billion (in 2018 dollars) for the remaining five-unit MCR program and the remainder of the AM program beyond 2023. Future MCR investments will be subject to discrete decisions for each unit with specified off-ramps available for Bruce Power and the IESO. Bruce Power's current contract price of approximately $68 per MWh is expected to increase to approximately $75 per MWh on April 1, 2019 to reflect capital to be invested under the Unit 6 MCR program and the AM program as well as normal annual inflation adjustments. |
14 | TransCanada Annual information form 2018 |
Date | Description of development |
Ontario Solar | |
2017 | In October 2017, we entered into an agreement to sell our Ontario solar assets comprised of eight facilities with a total generating capacity of 76 MW, to Axium Infinity Solar LP. On December 19, 2017, we closed the sale for $541 million, before post-closing adjustments, resulting in a gain of $127 million ($136 million after-tax). |
Coolidge Generating Station | |
2018 | On December 14, 2018, we entered into an agreement to sell our Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC for approximately US$465 million, subject to timing of closing and related adjustments. Salt River Project Agriculture Improvement and Power District, the PPA counterparty, exercised its contractual right of first refusal on a sale to a third party in January 2019. The sale will result in an estimated gain of approximately $65 million ($50 million after tax), to be recognized upon closing of the sale transaction which is expected to occur in mid-2019. |
U.S. POWER | |
Ironwood | |
2016 | In February 2016, we acquired the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM Interconnection area power market. |
Monetization of U.S. Northeast Power Business | |
2016 | In November 2016, we announced the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors and the sale of TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC. |
2017 | In April 2017, we closed the sale of TC Hydro to Great River Hydro, LLC for US$1.07 billion, before post-closing adjustments and recorded a gain of $715 million ($440 million after-tax). In June 2017, we closed the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC for US$2.029 billion, before post-closing adjustments. In addition to the pre-tax losses of approximately $829 million ($863 million after-tax) and a $1,085 million ($656 million after-tax) impairment charge that we recorded in 2016 upon entering into agreements to sell these assets, an additional pre-tax loss on sale of approximately $211 million ($167 million after-tax) was recorded in 2017, primarily related to an adjustment to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close, partially offset by insurance recoveries for a portion of the repair costs. Proceeds from the sale transactions were used to fully retire the remaining bridge facilities that partially funded the acquisition of Columbia. On December 22, 2017, we entered into an agreement to sell our U.S. power retail contracts as part of the continued wind down of our U.S. power marketing operations. |
2018 | In March 2018, we closed the sale of our U.S. power retail contracts for proceeds of approximately US$23 million and recognized income of US$10 million (US$7 million after-tax). |
TransCanada Annual information form 2018 | 15 |
16 | TransCanada Annual information form 2018 |
TransCanada Annual information form 2018 | 17 |
Calgary (includes U.S. employees working in Canada) | 2,646 | |
Western Canada (excluding Calgary) | 560 | |
Eastern Canada | 322 | |
Houston (includes Canadian employees working in the U.S.) | 801 | |
U.S. Midwest | 877 | |
U.S. Northeast | 257 | |
U.S. Southeast/ Gulf Coast (excluding Houston) | 1,240 | |
U.S. West Coast | 87 | |
Mexico | 291 | |
Total | 7,081 |
18 | TransCanada Annual information form 2018 |
• | planning – risk and regulatory assessment, objective and target setting, defining roles and responsibilities |
• | implementing – development and implementation of programs, procedures and standards to manage operational risk |
• | reporting – incident reporting and investigation, and performance monitoring |
• | action – assurance activities and review of performance by management. |
• | overall HSSE corporate governance |
• | operational performance and preventative maintenance metrics |
• | asset integrity programs |
• | emergency preparedness, incident response and evaluation |
• | people and process safety performance metrics |
• | our Environment Program |
• | developments in and compliance with applicable legislation and regulations, including those related to the environment |
• | prevention, mitigation and management of risks related to HSSE matters, including climate-change related risks which may adversely impact TransCanada |
• | sustainability matters, including social, environmental and climate-change related matters |
• | management's approach to voluntary public disclosure on HSSE matters. |
TransCanada Annual information form 2018 | 19 |
TransCanada Annual information form 2018 | 20 |
TransCanada Annual information form 2018 | 21 |
22 | TransCanada Annual information form 2018 |
Series of first preferred shares | Initial redemption date | Redemption/conversion dates | Spread (%) | |
Series 1 preferred shares | December 31, 2014 | December 31, 2019 and every fifth year thereafter | 1.92 | |
Series 2 preferred shares | — | December 31, 2019 and every fifth year thereafter | 1.92 | |
Series 3 preferred shares | June 30, 2015 | June 30, 2020 and every fifth year thereafter | 1.28 | |
Series 4 preferred shares | — | June 30, 2020 and every fifth year thereafter | 1.28 | |
Series 5 preferred shares | January 30, 2016 | January 30, 2021 and every fifth year thereafter | 1.54 | |
Series 6 preferred shares | — | January 30, 2021 and every fifth year thereafter | 1.54 | |
Series 7 preferred shares | April 30, 2019 | April 30, 2019 and every fifth year thereafter | 2.38 | |
Series 8 preferred shares | — | April 30, 2024 and every fifth year thereafter | 2.38 | |
Series 9 preferred shares | October 30, 2019 | October 30, 2019 and every fifth year thereafter | 2.35 | |
Series 10 preferred shares | — | October 30, 2024 and every fifth year thereafter | 2.35 | |
Series 11 preferred shares | November 30, 2020 | November 30, 2020 and every fifth year thereafter | 2.96 | |
Series 12 preferred shares | — | November 28, 2025 and every fifth year thereafter | 2.96 | |
Series 13 preferred shares | May 31, 2021 | May 31, 2021 and every fifth year thereafter | 4.69 | |
Series 14 preferred shares | — | May 29, 2026 and every fifth year thereafter | 4.69 | |
Series 15 preferred shares | May 31, 2022 | May 31, 2022 and every fifth year thereafter | 3.85 | |
Series 16 Preferred shares | — | May 31, 2027 and every fifth year thereafter | 3.85 |
TransCanada Annual information form 2018 | 23 |
Moody's | S&P | Fitch | DBRS | ||
TCPL - Senior unsecured debt Debentures Medium-term notes | A3 A3 | BBB+ BBB+ | A- A- | A (low) A (low) | |
TCPL - Junior subordinated notes | Baa1 | BBB- | Not rated | BBB | |
TransCanada Trust - Subordinated trust notes | Baa2 | BBB- | BBB | Not rated | |
TransCanada Corporation - Preferred shares | Not rated | P-2 (Low) | BBB | Pfd-2 (low) | |
Commercial paper (TCPL and TCPL guaranteed) | P-2 | A-2 | F2 | R-1 (low) | |
Trend/ rating outlook | Negative | Stable | Stable | Stable |
24 | TransCanada Annual information form 2018 |
TransCanada Annual information form 2018 | 25 |
Type | Issue Date | Stock Symbol |
Series 1 preferred shares | September 30, 2009 | TRP.PR.A |
Series 2 preferred shares | December 31, 2014 | TRP.PR.F |
Series 3 preferred shares | March 11, 2010 | TRP.PR.B |
Series 4 preferred shares | June 30, 2015 | TRP.PR.H |
Series 5 preferred shares | June 29, 2010 | TRP.PR.C |
Series 6 preferred shares | February 1, 2016 | TRP.PR.I |
Series 7 preferred shares | March 4, 2013 | TRP.PR.D |
Series 9 preferred shares | January 20, 2014 | TRP.PR.E |
Series 11 preferred shares | March 2, 2015 | TRP.PR.G |
Series 13 preferred shares | April 20, 2016 | TRP.PR.J |
Series 15 preferred shares | November 21, 2016 | TRP.PR.K |
Month | TSX (TRP) | NYSE (TRP) | |||||||||
High ($) | Low ($) | Close ($) | Volume traded | High (US$) | Low (US$) | Close (US$) | Volume traded | ||||
December 2018 | $56.06 | $47.90 | $48.75 | 56,220,000 | $42.08 | $34.58 | $35.70 | 36,623,610 | |||
November 2018 | $54.62 | $49.98 | $54.45 | 46,569,110 | $41.15 | $38.15 | $40.92 | 32,349,090 | |||
October 2018 | $54.23 | $48.92 | $49.64 | 50,660,000 | $42.29 | $37.24 | $37.72 | 34,308,100 | |||
September 2018 | $56.49 | $52.06 | $52.26 | 44,470,520 | $42.92 | $39.86 | $40.46 | 19,278,150 | |||
August 2018 | $59.27 | $55.43 | $55.58 | 36,470,000 | $45.63 | $42.48 | $42.60 | 20,027,370 | |||
July 2018 | $59.51 | $56.09 | $58.51 | 30,528,890 | $45.09 | $42.25 | $44.95 | 20,225,410 | |||
June 2018 | $58.50 | $53.26 | $56.88 | 45,610,000 | $43.80 | $41.14 | $43.20 | 25,597,000 | |||
May 2018 | $56.58 | $53.61 | $54.28 | 41,648,980 | $44.05 | $41.18 | $41.83 | 38,214,990 | |||
April 2018 | $56.40 | $50.28 | $54.44 | 39,940,000 | $44.73 | $39.16 | $42.45 | 31,004,740 | |||
March 2018 | $57.72 | $51.63 | $53.28 | 48,747,930 | $44.65 | $40.02 | $41.31 | 34,601,117 | |||
February 2018 | $58.75 | $52.05 | $55.50 | 40,890,194 | $46.19 | $41.24 | $43.22 | 29,063,863 | |||
January 2018 | $62.24 | $55.67 | $56.63 | 40,455,560 | $49.89 | $45.14 | $46.04 | 28,858,757 |
26 | TransCanada Annual information form 2018 |
Month | Preferred Shares | ||||||||||
Series 1 | Series 2 | Series 3 | Series 4 | Series 5 | Series 6 | Series 7 | Series 9 | Series 11 | Series 13 | Series 15 | |
December 2018 High Low Close Volume traded | $ 16.74 $ 14.09 $ 16.56 252,690 | $ 17.00 $ 14.69 $ 16.70 409,089 | $ 14.15 $ 11.96 $ 13.56 177,350 | $ 14.29 $ 11.99 $ 13.93 108,670 | $ 15.22 $ 12.70 $ 14.18 329,450 | $ 16.19 $ 13.22 $ 14.22 41,413 | $ 19.03 $ 16.40 $ 18.40 592,330 | $ 20.20 $ 16.78 $ 18.72 543,490 | $ 20.83 $ 18.26 $ 20.33 152,424 | $ 25.96 $ 25.15 $ 25.41 527,130 | $ 25.00 $ 23.70 $ 24.72 449,860 |
November 2018 High Low Close Volume traded | $ 19.80 $ 16.50 $ 16.50 115,846 | $ 20.16 $ 16.50 $ 17.00 85,858 | $ 16.99 $ 14.01 $ 14.08 95,340 | $ 17.29 $ 13.81 $ 13.98 310,853 | $ 17.44 $ 14.55 $ 14.99 372,220 | $ 17.99 $ 15.44 $ 15.80 24,776 | $ 22.13 $ 18.65 $ 18.79 191,709 | $ 22.09 $ 18.75 $ 18.79 168,174 | $ 23.77 $ 19.86 $ 20.40 127,440 | $ 26.23 $ 25.07 $ 25.49 647,000 | $ 25.94 $ 24.37 $ 24 85 293,860 |
October 2018 High Low Close Volume traded | $ 20.85 $ 18.36 $ 19.85 260,120 | $ 21.30 $ 18.56 $ 19.46 179,613 | $ 17.68 $ 15.32 $ 16.23 150,685 | $ 17.84 $ 15.76 $ 16.69 73,635 | $ 18.18 $ 15.84 $ 16.89 196,840 | $ 18.98 $ 16.75 $ 17.32 20,857 | $ 22.90 $ 20.48 $ 21.71 482,790 | $ 23.04 $ 20.25 $ 21.71 348,420 | $ 24.90 $ 22.26 $ 23.21 133,360 | $ 26.53 $ 25.38 $ 26.17 393,180 | $ 26.25 $ 24.90 $ 25.72 390,230 |
September 2018 High Low Close Volume traded | $ 20.71 $ 20.18 $ 20.69 109,148 | $ 20.87 $ 20.55 $ 20.80 37,300 | $ 17.55 $ 16.85 $ 17.49 43,974 | $ 17.53 $ 17.25 $ 17.50 33,110 | $ 17.95 $ 17.32 $ 17.62 363,720 | $ 18.67 $ 18.25 $ 18.67 6,210 | $ 23.05 $ 22.34 $ 22.69 158,110 | $ 23.07 $ 22.54 $ 22.67 133,770 | $ 24.49 $ 24.23 $ 24.38 110,587 | $ 26.55 $ 26.07 $ 26.46 85,649 | $ 26.15 $ 25.58 $ 26.08 240,590 |
August 2018 High Low Close Volume traded | $ 20.65 $ 20.21 $ 20.49 156,853 | $ 20.89 $ 20.36 $ 20.80 172,356 | $ 17.35 $ 16.95 $ 17.25 40,120 | $ 17.51 $ 17.15 $ 17.47 17,870 | $ 17.85 $ 17.62 $ 17.77 263,179 | $ 18.63 $ 18.11 $ 18.63 35,778 | $ 22.98 $ 22.45 $ 22.95 139,340 | $ 22.89 $ 22.39 $ 22.70 645,697 | $ 24.50 $ 23.89 $ 24.40 95,118 | $ 26.62 $ 26.04 $ 26.30 174,690 | $ 26.24 $ 25.76 $ 25.91 348,670 |
July 2018 High Low Close Volume traded | $ 20.78 $ 20.24 $ 20.36 51,108 | $ 20.83 $ 20.01 $ 20.50 705,451 | $ 17.31 $ 16.74 $ 17.14 243,087 | $ 17.49 $ 17.00 $ 17.16 43,329 | $ 17.99 $ 17.50 $ 17.63 287,284 | $ 18.30 $ 17.53 $ 18.10 15,777 | $ 22.99 $ 22.42 $ 22.80 214,720 | $ 22.78 $ 22.40 $ 22.66 815,601 | $ 24.59 $ 23.93 $ 24.19 130,962 | $ 26.43 $ 26.02 $ 26.29 381,440 | $ 25.92 $ 25.38 $ 25.78 493,660 |
June 2018 High Low Close Volume traded | $ 20.45 $ 19.85 $ 20.24 70,105 | $ 20.25 $ 19.96 $ 20.05 108,445 | $ 17.28 $ 16.71 $ 17.08 68,682 | $ 17.00 $ 16.72 $ 16.84 44,271 | $ 18.01 $ 17.60 $ 17.67 290,163 | $ 18.45 $ 17.99 $ 18.06 38,153 | $ 23.24 $ 22.54 $ 22.58 107,440 | $ 23.21 $ 22.31 $ 22.49 92,703 | $ 24.40 $ 23.88 $23.92 55,196 | $ 26.26 $ 25.83 $ 26.24 209,410 | $ 25.85 $ 25.39 $ 25.61 328,390 |
May 2018 High Low Close Volume traded | $ 20.80 $ 19.69 $ 20.15 238,030 | $ 20.71 $ 19.55 $ 20.00 377,217 | $ 17.25 $ 16.45 $ 16.80 325,450 | $ 17.75 $ 16.53 $ 17.00 38,170 | $ 18.07 $ 17.27 $ 17.77 701,502 | $ 18.62 $ 17.96 $ 17.96 18,932 | $ 23.66 $ 22.33 $ 22.65 669,200 | $ 23.38 $ 22.25 $ 22.64 557,091 | $ 24.62 $ 23.55 $ 23.97 86,608 | $ 26.45 $ 25.80 $ 26.18 506,560 | $ 26.15 $ 25.39 $ 25.78 661,240 |
April 2018 High Low Close Volume traded | $ 20.39 $ 19.46 $ 19.75 166,140 | $ 20.30 $ 19.50 $ 19.73 218,914 | $ 16.88 $16.30 $ 16.53 211,150 | $ 16.97 $ 16.29 $ 16.60 76,542 | $ 17.95 $ 17.21 $ 17.45 281,088 | $ 19.02 $ 18.09 $ 18.30 10,108 | $ 22.48 $ 21.75 $ 22.40 284,170 | $ 22.39 $ 21.80 $ 22.20 340,390 | $ 24.01 $ 23.46 $ 23.62 78,450 | $ 26.47 $ 26.15 $ 26.29 1,286,469 | $ 26.06 $ 25.57 $ 25.91 613,490 |
March 2018 High Low Close Volume traded | $ 20.89 $ 20.24 $ 20.49 200,698 | $ 20.78 $ 20.10 $ 20.46 71,565 | $ 17.26 $ 16.61 $ 16.95 125,455 | $ 17.24 $ 16.73 $ 16.93 58,736 | $ 18.15 $ 17.70 $ 17.99 82,615 | $ 18.89 $ 18.02 $ 18.60 15,500 | $ 23.70 $ 22.08 $ 22.20 239,180 | $ 23.73 $ 22.16 $ 22.24 227,894 | $24.37 $23.72 $23.90 169,419 | $ 26.50 $ 26.05 $ 26.40 375,189 | $ 26.05 $ 25.43 $ 26.05 400,078 |
February 2018 High Low Close Volume traded | $ 21.50 $ 20.71 $ 20.97 70,291 | $ 21.67 $ 20.73 $ 20.77 198,200 | $ 17.69 $17.00 $ 17.32 64,877 | $ 17.64 $ 17.13 $ 17.27 43,216 | $ 18.70 $ 17.70 $18.15 107,907 | $ 18.89 $ 18.05 $ 18.34 18,775 | $ 24.10 $ 22.91 $ 23.35 503,638 | $ 24.34 $ 23.15 $ 23.42 144,406 | $ 24.60 $ 23.97 $ 24.43 259,747 | $ 26.62 $ 25.86 $ 26.25 193,482 | $ 26.06 $ 25.29 $ 25.88 689,659 |
January 2018 High Low Close Volume traded | $ 21.49 $ 19.89 $ 20.96 161,053 | $ 21.15 $ 19.31 $ 21.13 70,146 | $ 17.42 $ 16.15 $ 17.18 213,388 | $ 17.59 $ 15.74 $ 17.48 37, 607 | $ 18.69 $ 17.17 $ 18.30 280,163 | $ 19.53 $ 16.93 $ 18.60 26,970 | $ 24.00 $ 22.50 $ 23.99 371,922 | $ 24.56 $ 23.23 $ 24.31 478,986 | $ 24.84 $ 24.20 $ 24.35 64,150 | $ 26.84 $ 26.40 $ 26.53 896,315 | $ 26.35 $ 25.85 $ 26.00 1,305,993 |
TransCanada Annual information form 2018 | 27 |
Name and place of residence | Principal occupation during the five preceding years | Director since | ||
Kevin E. Benson Calgary, Alberta Canada | Corporate director. Director, Winter Sport Institute (non-profit) from February 2015 to July 2018. Director, Calgary Airport Authority from January 2010 to December 2013. | 2005 | ||
Stéphan Crétier Dubai, United Arab Emirates | Chairman, President and Chief Executive Officer, GardaWorld Security Corporation (GardaWorld) (private security services) and director of a number of GardaWorld’s direct and indirect subsidiaries, since 1999. | 2017 | ||
Russell K. Girling(1) Calgary, Alberta Canada | President and Chief Executive Officer, TransCanada since July 2010. Director, American Petroleum Institute since January 2015. Director, Nutrien Ltd. (formerly Agrium Inc.) (agriculture) since May 2006. | 2010 | ||
S. Barry Jackson Calgary, Alberta Canada | Corporate director. Director, WestJet Airlines Ltd. (airline) since February 2009. Director, Laricina Energy Ltd. (Laricina) (oil and gas, exploration and production) from December 2005 to November 2017. Director, Nexen Inc. (Nexen) (oil and gas, exploration and production) from 2001 to June 2013, and Chair of the Board, Nexen from 2012 to June 2013. | 2002 | ||
Randy Limbacher Houston, Texas U.S.A. | Chief Executive Officer, Meridian Energy, LLC (oil and gas exploration and production) since June 2017. Director, CARBO Ceramics Inc. since July 2007. President and Chief Executive Officer, Samson Resources Corporation (Samson) (oil and gas exploration and production) from April 2013 to December 2015. Vice Chairman and director, Samson Resources until March 2017. | 2018 | ||
John E. Lowe Houston, Texas U.S.A. | Non-executive Chairman of the Board, Apache Corporation (Apache) (oil and gas) since May 2015. Director, Phillips 66 Company (energy infrastructure) since May 2012. Director, Apache since July 2013. Senior Executive Adviser at Tudor, Pickering, Holt & Co. LLC (energy investment and merchant banking) since September 2012. Director, Agrium Inc. (agriculture) from May 2010 to August 2015. | 2015 | ||
Paula Rosput Reynolds Seattle, Washington U.S.A. | President and Chief Executive Officer, PreferWest, LLC (business advisory group) since October 2009. Director, CBRE Group, Inc. (commercial real estate) since March 2016. Director, BP p.l.c. (oil and gas) since May 2015. Director, BAE Systems plc. (aerospace, defence, information security) since April 2011. Director, Siluria Technologies Inc. (natural gas) from February 2015 to June 2017. Director, Delta Air Lines, Inc. (airline) from August 2004 to June 2015. Director, Anadarko Petroleum Corporation (oil and gas, exploration and production) from August 2007 to May 2014. | 2011 | ||
Mary Pat Salomone Naples, Florida U.S.A. | Corporate director. Director, Herc Rentals (equipment rental) since July 2016. Director, Intertape Polymer Group (manufacturing) since November 2015. Senior Vice-President and Chief Operating Officer, The Babcock & Wilcox Company (energy infrastructure) from January 2010 to June 2013. | 2013 | ||
Indira Samarasekera Vancouver, British Columbia Canada | Senior Advisor, Bennett Jones LLP (law firm) since September 2015. Director, Stelco Holdings Inc. (manufacturing) since May 2018. Director, Magna International Inc. (automotive manufacturing) since May 2014 and the Bank of Nova Scotia (Scotiabank) (chartered bank) since May 2008. Member, selection panel for Canada's outstanding chief executive officer. Member, The TriLateral Commission since August 2016. | 2016 | ||
D. Michael G. Stewart Calgary, Alberta Canada | Corporate director. Director, Pengrowth Energy Corporation (oil and gas, exploration and production) since December 2010. Director, CES Energy Solutions Corp. (oilfield services) since January 2010. Director, Northpoint Resources Ltd. (oil and gas, exploration and production) from July 2013 to February 2015. | 2006 |
28 | TransCanada Annual information form 2018 |
Name and place of residence | Principal occupation during the five preceding years | Director since | ||
Siim A. Vanaselja Toronto, Ontario Canada | Corporate director. Chair of the Board, TransCanada since May 2017. Director, Power Financial Corporation (financial services) since May 2018. Director, RioCan Real Estate Investment Trust (real estate) since May 2017. Director, Great-West Lifeco Inc. (financial services) since May 2014. Director, Maple Leaf Sports and Entertainment Ltd. (sports, property management) from August 2012 to June 2017. Executive Vice-President and Chief Financial Officer, BCE Inc. and Bell Canada (telecommunications and media) from January 2001 to June 2015. | 2014 | ||
Thierry Vandal Mamaroneck, New York U.S.A. | President, Axium Infrastructure US, Inc. (independent infrastructure fund management firm) and Director, Axium Infrastructure Inc. since 2015. Director, Royal Bank of Canada (RBC) (chartered bank) since 2015. Member, International Advisory Board of École des Hautes Etudes Commerciales Montréal since October 2017. | 2017 |
• | was the subject of a cease trade or similar order, or an order denying that company any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days |
• | was involved in an event that resulted in the company being subject to one of the above orders after the director or executive officer no longer held that role with the company, which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer |
• | while acting in that capacity, or within a year of acting in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company. |
• | become bankrupt |
• | made a proposal under any legislation relating to bankruptcy or insolvency |
• | become subject to or launched any proceedings, arrangement or compromise with any creditors, or |
• | had a receiver, receiver manager or trustee appointed to hold any of their assets. |
• | any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or |
• | any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision. |
TransCanada Annual information form 2018 | 29 |
Director | Audit committee | Governance committee | Health, Safety, Sustainability & Environment committee | Human Resources committee |
Kevin E. Benson | Chair | ü | ||
Stéphan Crétier | ü | ü | ||
S. Barry Jackson | ü | ü | ||
Randy Limbacher | ü | ü | ||
John E. Lowe | Chair | ü | ||
Paula Rosput Reynolds | ü | Chair | ||
Mary Pat Salomone | ü | ü | ||
Indira Samarasekera | ü | ü | ||
D. Michael G. Stewart | ü | Chair | ||
Siim A. Vanaselja (Chair) | ü | ü | ||
Thierry Vandal | ü | ü |
30 | TransCanada Annual information form 2018 |
Name | Present position held | Principal occupation during the five preceding years |
Russell K. Girling | President and Chief Executive Officer | President and Chief Executive Officer. |
Stanley G. Chapman, III | Executive Vice-President and President, U.S. Natural Gas Pipelines | Prior to April 2017, Senior Vice-President and General Manager, U.S. Natural Gas Pipelines. Prior to July 2016 Executive Vice-President and Chief Commercial Officer of Columbia Pipeline Group, Inc. |
Kristine L. Delkus(1) | Executive Vice-President, Stakeholder Relations and General Counsel | Prior to February 1, 2019, Executive Vice-President, Stakeholder Relations and Technical Services and General Counsel. Prior to April 2017, Executive Vice-President, Stakeholder Relations and General Counsel. Prior to October 2015, Executive Vice-President, General Counsel and Chief Compliance Officer. Prior to March 2014, Senior Vice-President, Pipelines Law and Regulatory Affairs (TCPL). |
Wendy L. Hanrahan | Executive Vice-President, Corporate Services | Executive Vice-President, Corporate Services. |
Karl R. Johannson(2) | Executive Vice-President | Prior to January 1, 2019, Executive Vice-President and President, Canada and Mexico Natural Gas Pipelines and Energy. Prior to April 2017, Executive Vice-President, Natural Gas Pipelines. |
Donald R. Marchand | Executive Vice-President and Chief Financial Officer | Prior to February 2017, Executive Vice-President, Corporate Development and Chief Financial Officer. Prior to October 2015, Executive Vice-President and Chief Financial Officer. |
Paul E. Miller | Executive Vice-President, Technical Centre and President, Liquids Pipelines | Prior to February 1, 2019, Executive Vice-President and President, Liquids Pipelines. Prior to March 2014, Senior Vice-President, Oil Pipelines. |
Francois L. Poirier | Executive Vice-President, Corporate Development and Strategy and President, Mexico Natural Gas Pipelines and Energy | Prior to January 1, 2019, Executive Vice-President, Strategy and Corporate Development. Prior to February 2017, Senior Vice-President, Strategy and Corporate Development. Prior to October 2015, President, Energy East Pipeline. Prior to September 2015, President, Wells Fargo Securities Canada, Ltd. |
Tracy A. Robinson | Executive Vice-President and President, Canadian Natural Gas Pipelines | Prior to January 1, 2019, Executive Vice-President, Canadian Natural Gas Pipelines. Prior to September 2018, Senior Vice-President, Canadian Natural Gas Pipelines. Prior to November 2017, Senior Vice-President, Canada, Natural Gas Pipelines Division, Canada (TCPL). Prior to April 2017, Senior Vice-President, Canada, Natural Gas Pipelines Division (TCPL). Prior to March 2017, Vice-President, Supply Chain (TCPL). Prior to October 2015, Vice-President, Transportation, Liquids Pipelines Division (TCPL). Prior to September 2014, Vice-President, Marketing and Sales, Canadian Pacific Railway Limited. |
TransCanada Annual information form 2018 | 31 |
Name | Present position held | Principal occupation during the five preceding years |
Gloria Hartl | Vice-President, Risk Management | Prior to February 1, 2019, Director, Corporate Planning. Prior to December 2017, Manager, Short-Term Planning & Forecasting. |
Dennis P. Hebert | Vice-President, Taxation | Prior to June 2017, Vice-President, Tax and Insurance, Spectra Energy (Spectra). Prior to June 2014, General Manager, Tax (Spectra). |
R. Ian Hendy | Vice-President and Treasurer | Prior to December 2017, Director, Financial Trading and Assistant Treasurer. |
Joel E. Hunter | Senior Vice-President, Capital Markets | Prior to December 2017, Vice-President, Finance and Treasurer. Prior to August 2015, Vice-President, Finance. |
Christine R. Johnston | Vice-President, Law and Corporate Secretary | Prior to June 2014, Vice-President and Corporate Secretary. |
G. Glenn Menuz | Vice-President and Controller | Vice-President and Controller. |
• | National Instrument 52-110, Audit Committees |
• | National Policy 58-201, Corporate Governance Guidelines, and |
• | National Instrument 58-101, Disclosure of Corporate Governance Practices. |
32 | TransCanada Annual information form 2018 |
TransCanada Annual information form 2018 | 33 |
($ millions) | 2018 | 2017 |
Audit fees | $10.3 | $9.7 |
• audit of the annual consolidated financial statements | ||
• services related to statutory and regulatory filings or engagements | ||
• review of interim consolidated financial statements and information contained in various prospectuses and other securities offering documents | ||
Audit-related fees | $0.1 | $0.1 |
• services related to the audit of the financial statements of TransCanada pipeline abandonment trusts and certain post-retirement plans | ||
Tax fees | $1.2 | $0.8 |
• Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings | ||
All other fees | $0.2 | $0.2 |
• French translation services | ||
Total fees | $11.8 | $10.8 |
34 | TransCanada Annual information form 2018 |
1. | Additional information in relation to TransCanada may be found under TransCanada's profile on SEDAR (www.sedar.com). |
2. | Additional information including directors' and officers' remuneration and indebtedness, principal holders of TransCanada's securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TransCanada's Management Information Circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from the Corporate Secretary of TransCanada. |
3. | Additional financial information is provided in TransCanada's audited consolidated financial statements and MD&A for its most recently completed financial year. |
TransCanada Annual information form 2018 | 35 |
Units of measure | ||
Bbl/d | Barrel(s) per day | |
Bcf | Billion cubic feet | |
Bcf/d | Billion cubic feet per day | |
GJ | Gigajoule | |
hp | horsepower | |
km | Kilometres | |
MMcf/d | Million cubic feet per day | |
MW | Megawatt(s) | |
MWh | Megawatt hours | |
PJ/d | Petajoules per day | |
TJ/d | Terajoules per day | |
General terms and terms related to our operations | ||
AM | asset management | |
ATM | An at-the-market distribution program allowing us to issue common shares from treasury at the prevailing market price | |
B.C. | British Columbia | |
bitumen | A thick, heavy oil that must be diluted to flow (also see: diluent). One of the components of the oil sands, along with sand, water and clay | |
diluent | A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines | |
Empress | A major delivery/receipt point for natural gas near the Alberta/ Saskatchewan border | |
FID | Final investment decision | |
FEIS | Final Environmental Impact Statement | |
force majeure | Unforeseeable circumstances that prevent a party to a contract from fulfilling it | |
GHG | Greenhouse gas | |
HSSE | Health, safety, sustainability and environment | |
investment base | Includes rate base as well as assets under construction | |
LDC | Local distribution company | |
LNG | Liquefied natural gas | |
MCR | major component replacement | |
PJM Interconnection area (PJM) | A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia | |
PPA | Power purchase arrangement | |
rate base | Average assets in service, working capital and deferred amounts used in setting of regulated rates | |
TSA | Transportation service agreements | |
WCSB | Western Canada Sedimentary Basin | |
Year End | Year ended December 31, 2018 |
Accounting terms | ||
AFUDC | Allowance for funds used during construction | |
DRP | Dividend reinvestment plan | |
GAAP | U.S. generally accepted accounting principles | |
LTAA | Long Term Adjustment Account | |
OM&A | Operating, maintenance & administration | |
ROE | Return on common equity | |
Government and regulatory bodies terms | ||
AER | Alberta Energy Regulator | |
BCEAO | Environmental Assessment Office (British Columbia) | |
CBCA | Canada Business Corporations Act | |
CCAA | Companies' Creditors Arrangement Act | |
CFE | Comisión Federal de Electricidad (Mexico) | |
CPCN | Certificate of Public Convenience and Necessity | |
CQDE | Québec Environmental Law Centre/ Centre québécois du droit de l'environnement | |
DOJ | U.S. Department of Justice | |
DOS | U.S. Department of State | |
FERC | Federal Energy Regulatory Commission (U.S.) | |
IESO | Independent Electricity System Operator | |
HQ | Hydro-Québec Distribution | |
MDDELCC | Ministère du Développement durable, de l'Environnement et la Lutte contre les changements climatiques (Québec) | |
NAFTA | North American Free Trade Agreement | |
NEB | National Energy Board (Canada) | |
NRC | National Response Center | |
NYSE | New York Stock Exchange | |
OGC | Oil and Gas Commission (British Columbia) | |
PHMSA | Pipeline and Hazardous Materials Safety and Administration | |
PSC | Public Service Commission (Nebraska) | |
PUC | Public Utilities Commission (South Dakota) | |
SEC | U.S. Securities and Exchange Commission | |
SEIS | Supplemental environmental impact statement | |
TSX | Toronto Stock Exchange |
36 | TransCanada Annual information form 2018 |
Metric | Imperial | Factor |
Kilometres (km) | Miles | 0.62 |
Millimetres | Inches | 0.04 |
Gigajoules | Million British thermal units | 0.95 |
Cubic metres* | Cubic feet | 35.3 |
Kilopascals | Pounds per square inch | 0.15 |
Degrees Celsius | Degrees Fahrenheit | to convert to Fahrenheit multiply by 1.8, then add 32 degrees; to convert to Celsius subtract 32 degrees, then divide by 1.8 |
* | The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius. |
TransCanada Annual information form 2018 | 37 |
• | Company’s financial accounting and reporting process; |
• | integrity of the financial statements; |
• | Company’s internal control over financial reporting; |
• | external financial audit process; |
• | compliance by the Company with legal and regulatory requirements; and |
• | independence and performance of the Company’s internal and external auditor. |
(a) | review, discuss with management and the external auditor and recommend to the Board for approval, the Company’s audited annual consolidated financial statements, annual information form, management’s discussion and analysis (MD&A), all financial information in prospectuses and other offering memoranda, financial statements required by securities regulators, all prospectuses and all documents which may be incorporated by reference into a prospectus, including, without limitation, the annual management information circular, but excluding any pricing or prospectus supplement relating to the issuance of debt securities of the Company; |
(b) | review, discuss with management and the external auditor and recommend to the Board for approval, the release to the public of the Company’s interim reports, including the consolidated financial statements, MD&A and press releases on quarterly financial results; |
(c) | review and discuss with management and the external auditor the use of non-GAAP information and the applicable reconciliation; |
(d) | review and discuss with management any financial outlook or future-oriented financial information disclosure in advance of its public release; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide financial projections or presentations to credit rating agencies; |
(e) | review with management and the external auditor major issues regarding accounting policies and auditing practices, |
38 | TransCanada Annual information form 2018 |
(ii) | all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and |
(iii) | other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences. |
(g) | review with management and the external auditor the effect of regulatory and accounting developments on the Company’s financial statements; |
(a) | review with management and the external auditor the effect of any off-balance sheet structures on the Company’s financial statements; |
(i) | review with management, the external auditor and, if necessary, legal counsel, any litigation, claim or contingency, including arbitration and tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements; |
(j) | review disclosures made to the Audit Committee by the Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO) during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls; and |
(k) | discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies. |
(a) | review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies. |
(a) | review and approve the audit plans of the internal auditor of the Company including the degree of coordination between such plans and those of the external auditor and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts; |
(b) | review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management’s response thereto; |
(c) | review compliance with the Company’s policies and avoidance of conflicts of interest; |
(d) | review the report prepared by the internal auditor on officers’ expenses and aircraft usage; |
(e) | review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process with subsidiaries and affiliates; and |
(f) | ensure the internal auditor has access to the Chair of the Audit Committee, the Board and the CEO and meet separately with the internal auditor to review with him or her any problems or difficulties he or she may have encountered and specifically: |
(i) | any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management; |
(ii) | any changes required in the planned scope of the internal audit; and |
TransCanada Annual information form 2018 | 39 |
(a) | review any letter, report or other communication from the external auditor in respect of any identified weakness in internal control or unadjusted difference and management’s response and follow‑up, inquire regularly of management and the external auditor of any significant issues between them and how they have been resolved, and intervene in the resolution if required; |
(b) | receive and review annually the external auditor’s formal written statement of independence delineating all relationships between itself and the Company; |
(c) | meet separately with the external auditor to review any problems or difficulties the external auditor may have encountered and specifically: |
(i) | any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management; and |
(d) | meet with the external auditor prior to the audit to review the planning and staffing of the audit; |
(e) | receive and review annually the external auditor's written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues; |
(f) | review and evaluate the external auditor, including the lead partner of the external auditor team; and |
(g) | ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years. |
(a) | pre-approve all audit services (which may entail providing comfort letters in connection with securities underwritings) and all permitted non‑audit services, other than non‑audit services where: |
(i) | the aggregate amount of all such non‑audit services provided to the Company that were not pre-approved constitutes not more than five percent of the total fees paid by the Company and its subsidiaries to the external auditor during the fiscal year in which the non‑audit services are provided; |
(ii) | such services were not recognized by the Company at the time of the engagement to be non‑audit services; and |
(iii) | such services are promptly brought to the attention of the Audit Committee and approved, prior to the completion of the audit, by the Audit Committee or by one or more members of the Audit Committee to whom authority to grant such approvals has been delegated by the Audit Committee. |
(b) | approval by the Audit Committee of a non‑audit service to be performed by the external auditor shall be disclosed as required under securities laws and regulations; |
(c) | the Audit Committee may delegate to one or more designated members of the Audit Committee the authority to grant pre-approvals required by this subsection. The decisions of any member to whom authority is delegated to pre-approve an activity shall be presented to the Audit Committee at its first scheduled meeting following such pre-approval; and |
(d) | if the Audit Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of this subsection. |
(a) | review and recommend to the Board for approval the implementation of, and significant amendments to, policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s code of business ethics (COBE), risk management and financial reporting policies; |
40 | TransCanada Annual information form 2018 |
(b) | obtain reports from management, the Company’s senior internal auditing executive and the external auditor and report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s COBE; |
(c) | establish a non‑traceable, confidential and anonymous system by which callers may ask for advice or report any ethical or financial concern, ensure that procedures for the receipt, retention and treatment of complaints in respect of accounting, internal controls and auditing matters are in place, and receive reports on such matters as necessary; |
(d) | annually review and assess the adequacy of the Company’s public disclosure policy; and |
(e) | review and approve the Company’s hiring policy for partners, employees and former partners and employees of the present and former external auditor (recognizing the Sarbanes-Oxley Act of 2002 does not permit the CEO, controller, CFO or chief accounting officer to have participated in the Company’s audit as an employee of the external auditor during the preceding one-year period) and monitor the Company’s adherence to the policy. |
(a) | review and approve annually the Statement of Investment Beliefs for the Company’s pension plans; |
(b) | delegate the ongoing administration and management of the financial aspects of the Canadian pension plans to the Pension Committee comprised of members of the Company’s management team appointed by the Human Resources Committee, in accordance with the Pension Committee Charter, which terms shall be approved by both the Audit Committee and the Human Resources Committee, and the terms of the Statement of Investment Beliefs; |
(c) | monitor the financial management activities of the Pension Committee and receive updates at least annually from the Pension Committee on the investment of the Plan assets to ensure compliance with the Statement of Investment Beliefs; |
(d) | provide advice to the Human Resources Committee on any proposed changes in the Company’s pension plans in respect of any significant effect such changes may have on pension financial matters; |
(e) | review and consider financial and investment reports and the funded status relating to the Company’s pension plans and recommend to the Board on pension contributions; |
(f) | receive, review and report to the Board on the actuarial valuation and funding requirements for the Company’s pension plans; |
(g) | approve the initial selection or change of actuary for the Company’s pension plans; and |
(h) | approve the appointment or termination of the pension plans’ auditor. |
(a) | review and approve the engagement and related fees of the auditor for any plan of a U.S. subsidiary that offers Company stock to employees as an investment option under the plan. |
(a) | review annually the reports of the Company’s representatives on certain audit committees of subsidiaries and affiliates of the Company and any significant issues and auditor recommendations concerning such subsidiaries and affiliates; and |
(b) | oversee succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers’ group. |
(a) | review quarterly, the report of the Chief Information Officer (or such other appropriate Company representative) on information security controls, education and awareness. |
TransCanada Annual information form 2018 | 41 |
(a) | review and approve the agenda for each meeting of the Audit Committee and, as appropriate, consult with members of management; |
(b) | preside over meetings of the Audit Committee; |
(c) | make suggestions and provide feedback from the Audit Committee to management regarding information that is or should be provided to the Audit Committee; |
(d) | report to the Board on the activities of the Audit Committee relative to its recommendations, resolutions, actions and concerns; and |
(e) | meet as necessary with the internal and external auditor. |
42 | TransCanada Annual information form 2018 |
TransCanada Annual information form 2018 | 43 |
ABOUT THIS DOCUMENT | 6 | ||
ABOUT OUR BUSINESS | 10 | ||
• Three core businesses | 11 | ||
• Our strategy | 12 | ||
• 2018 FERC Actions | 14 | ||
• Impact of U.S. Tax Reform | 17 | ||
• Capital program | 18 | ||
• 2018 Financial highlights | 21 | ||
• Outlook | 28 | ||
NATURAL GAS PIPELINES BUSINESS | 29 | ||
CANADIAN NATURAL GAS PIPELINES | 37 | ||
U.S. NATURAL GAS PIPELINES | 42 | ||
MEXICO NATURAL GAS PIPELINES | 47 | ||
NATURAL GAS PIPELINES BUSINESS RISKS | 49 | ||
LIQUIDS PIPELINES | 51 | ||
ENERGY | 59 | ||
CORPORATE | 69 | ||
FINANCIAL CONDITION | 74 | ||
OTHER INFORMATION | 85 | ||
• Enterprise Risk Management | 85 | ||
• Controls and procedures | 93 | ||
• Critical accounting estimates | 94 | ||
• Financial instruments | 96 | ||
• Accounting changes | 99 | ||
• Reconciliation of comparable EBITDA and comparable EBIT to segmented earnings | 102 | ||
• Quarterly results | 103 | ||
GLOSSARY | 110 |
TransCanada Management's discussion and analysis 2018 | 5 |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available, including portfolio management |
• | expected dividend growth |
• | expected future credit ratings |
• | expected costs and schedules for planned projects, including projects under construction and in development |
• | expected capital expenditures and contractual obligations |
• | expected regulatory processes and outcomes, including the impact of the 2018 FERC Actions |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | the expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
• | regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | anticipated construction costs, schedules and completion dates |
• | access to capital markets, including portfolio management |
• | expected industry, market and economic conditions |
• | inflation rates and commodity prices |
• | interest, tax and foreign exchange rates |
• | nature and scope of hedging. |
6 | TransCanada Management's discussion and analysis 2018 |
• | our ability to successfully implement our strategic priorities and whether they will yield the expected benefits |
• | our ability to implement a capital allocation strategy aligned with maximizing shareholder value |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipeline businesses |
• | the amount of capacity payments and revenues from our energy business due to plant availability |
• | production levels within supply basins |
• | construction and completion of capital projects |
• | costs for labour, equipment and materials |
• | the availability and market prices of commodities |
• | access to capital markets on competitive terms |
• | interest, tax and foreign exchange rates |
• | performance and credit risk of our counterparties |
• | regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims |
• | changes in environmental and other laws and regulations |
• | competition in the pipeline and energy sectors |
• | unexpected or unusual weather |
• | acts of civil disobedience |
• | cyber security and technological developments |
• | economic conditions in North America as well as globally |
• | our ability to effectively anticipate and assess changes to government policies and regulations. |
TransCanada Management's discussion and analysis 2018 | 7 |
• | comparable EBITDA |
• | comparable EBIT |
• | comparable earnings |
• | comparable earnings per common share |
• | funds generated from operations |
• | comparable funds generated from operations |
• | comparable distributable cash flow |
• | comparable distributable cash flow per common share. |
• | certain fair value adjustments relating to risk management activities |
• | income tax refunds and adjustments to enacted tax rates |
• | gains or losses on sales of assets or assets held for sale |
• | legal, contractual and bankruptcy settlements |
• | impact of regulatory or arbitration decisions relating to prior year earnings |
• | restructuring costs |
• | impairment of goodwill, investments and other assets including certain ongoing maintenance and liquidation costs |
• | acquisition and integration costs. |
Non-GAAP measure | GAAP measure |
comparable EBITDA | segmented earnings |
comparable EBIT | segmented earnings |
comparable earnings | net income attributable to common shares |
comparable earnings per common share | net income per common share |
comparable funds generated from operations | net cash provided by operations |
comparable distributable cash flow | net cash provided by operations |
8 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 9 |
10 | TransCanada Management's discussion and analysis 2018 |
at December 31 | |||||||
(millions of $) | 2018 | 2017 | |||||
Total assets by segment | |||||||
Canadian Natural Gas Pipelines | 18,407 | 16,904 | |||||
U.S. Natural Gas Pipelines | 44,115 | 35,898 | |||||
Mexico Natural Gas Pipelines | 7,058 | 5,716 | |||||
Liquids Pipelines | 17,352 | 15,438 | |||||
Energy | 8,475 | 8,503 | |||||
Corporate | 3,513 | 3,642 | |||||
98,920 | 86,101 |
year ended December 31 | |||||||
(millions of $) | 2018 | 2017 | |||||
Total revenues by segment | |||||||
Canadian Natural Gas Pipelines | 4,038 | 3,693 | |||||
U.S. Natural Gas Pipelines | 4,314 | 3,584 | |||||
Mexico Natural Gas Pipelines | 619 | 570 | |||||
Liquids Pipelines | 2,584 | 2,009 | |||||
Energy1 | 2,124 | 3,593 | |||||
13,679 | 13,449 |
1 | Includes Cartier Wind assets until sold in 2018 and U.S. Northeast power generation assets and Ontario solar assets until sold in 2017. |
year ended December 31 | |||||||
(millions of $) | 2018 | 2017 | |||||
Comparable EBITDA by segment | |||||||
Canadian Natural Gas Pipelines | 2,379 | 2,144 | |||||
U.S. Natural Gas Pipelines | 3,035 | 2,357 | |||||
Mexico Natural Gas Pipelines | 607 | 519 | |||||
Liquids Pipelines | 1,849 | 1,348 | |||||
Energy1 | 752 | 1,030 | |||||
Corporate | (59 | ) | (21 | ) | |||
8,563 | 7,377 |
1 | Includes Cartier Wind assets until sold in 2018 and U.S. Northeast power generation assets and Ontario solar assets until sold in 2017. |
TransCanada Management's discussion and analysis 2018 | 11 |
1 | Maximize the full-life value of our infrastructure assets and commercial positions |
• Long-life infrastructure assets and long-term commercial arrangements are the cornerstones of our low risk business model • Our pipeline assets include large-scale natural gas and crude oil pipelines that connect low cost supply basins with stable and growing markets, generating predictable and sustainable cash flow and earnings • In Energy, long-term power sale agreements are used to manage and optimize our portfolio and to manage price volatility. | |
2 | Commercially develop and build new asset investment programs |
• We are developing high quality, long-life assets under our current $57 billion capital program, comprised of $36.6 billion in secured projects and $20.7 billion in largely commercially-supported projects under development. These investments will contribute incremental earnings and cash flows as they are placed in service • Our expertise in project development, managing construction risks and maximizing capital productivity ensures a disciplined approach to reliability, cost and schedule, resulting in superior service for our customers and returns to shareholders • As part of our growth strategy, we rely on this experience and our regulatory, commercial, financial, legal and operational expertise to successfully permit, fund, build and integrate new pipeline and other energy facilities • We are able to balance safety, profitability and social and environmental responsibility in our investing activities. | |
3 | Cultivate a focused portfolio of high quality development and investment options |
• We assess opportunities to develop and acquire energy infrastructure that complements our existing portfolio and diversifies access to attractive supply and market regions • We focus on pipeline and energy growth initiatives in core regions of North America and prudently manage development costs, minimizing capital-at-risk in early stages of projects • We will advance selected opportunities to full development and construction when market conditions are appropriate and project risks and returns are acceptable• We monitor trends in energy supply and demand, and maintain resilience through diversification, high quality cash flows and contractually underpinned assets. | |
4 | Maximize our competitive strengths |
• We are continually refining core competencies in areas such as safety, operational excellence, supply chain management, project execution and stakeholder relations to ensure we deliver maximum shareholder value over the short, medium and long terms. |
12 | TransCanada Management's discussion and analysis 2018 |
Our Competitive Advantage | |
Decades of experience in the energy infrastructure business and a disciplined approach to project management and capital investment give us our competitive edge. | |
• strong leadership: operating capabilities and strategy development; expertise in regulatory, legal, commercial and financing support | |
• a high quality portfolio: scale, presence and a low-risk and enduring business model that maximizes the full-life value of our long-life assets and commercial positions throughout all points in the business cycle | |
• disciplined operations: highly skilled in designing, building and operating energy infrastructure with a focus on operational excellence and a commitment to health, safety, sustainability and the environment which are paramount parts of our core values | |
• financial positioning: consistently strong financial performance; long-term financial stability and profitability; disciplined approach to capital investment; ability to access sizable amounts of competitively priced capital to support our growth; simplicity and understandability of our business and corporate structure; ability to balance an increasing common share dividend while preserving financial flexibility to fund our capital program in all market conditions | |
• long-term relationships: long-term, transparent relationships with key customers and stakeholders; clear communication of our prospects to equity and fixed income investors – both the upside and the risks – to build trust and support. |
Our Risk Preferences | |
The following is a discussion of our risk philosophy: | |
Live within our means | |
• Rely on internally-generated cash flows, existing debt capacity and portfolio management to finance new initiatives. Consider issuing new discrete common equity only for transformational opportunities, while the Corporate ATM program and DRP will be used as deemed appropriate. | |
Project risks known and acceptable | |
• Select investments with known, acceptable and manageable project execution risk, including stakeholder considerations. | |
Business underpinned by strong fundamentals | |
• Invest in assets that are investment-grade on a stand-alone basis, with stable cash flows, supported by strong underlying macroeconomic fundamentals, conducive regulations and/or long-term contracts with creditworthy counterparties. | |
Value 'A' grade credit ratings | |
• 'A' grade ratings are an important competitive advantage and TransCanada will seek to retain existing ratings while balancing the interests of equity and fixed income investors. | |
Prudent management of counterparty exposure | |
• Limit counterparty concentration and sovereign risk; seek diversification and solid commercial arrangements underpinned by strong fundamentals. |
TransCanada Management's discussion and analysis 2018 | 13 |
14 | TransCanada Management's discussion and analysis 2018 |
1. | Make a limited Natural Gas Act (NGA) Section 4 filing to reduce rates by the reduction in its cost-of-service shown in its Form 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s Form 501-G shows the pipeline’s estimated ROE as being 12 per cent or less. Under the Final Rule, and notwithstanding the Revised Policy Statement discussed above, a pipeline organized as an MLP is not required to eliminate its income tax allowance, but instead can reduce its rates to reflect the reduction in the federal corporate income tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base for rate-making purposes; |
2. | Commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. For pipelines that committed to file either by December 31, 2018, FERC would not initiate a Section 5 investigation of its rates prior to that date; |
3. | File a statement explaining its rationale for why it does not believe the pipeline's rates must change; or |
4. | Take no other action. FERC will consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case. |
Form 501-G Filing Option | Impact on Maximum Rates | Moratoriums and Mandatory Filing Requirements | ||||
Columbia Gas | Option 3 | No rate change proposed | Moratorium in effect through January 31, 2022. Comeback provision with new rates effective by February 1, 2022 | |||
Columbia Gulf | Option 3 | No rate change proposed | Moratorium in effect through June 30, 2019. Comeback provision with new rates effective by August 1, 2020 | |||
ANR | Option 3 | No rate change proposed | Moratorium in effect through July 31, 2019. Comeback provision with new rates effective by August 1, 2022 | |||
ANR Storage | Option 3 | No rate change proposed | No moratorium. Comeback provision with new rates effective by July 1, 2021 | |||
Millennium | Option 1 - filing accepted by FERC | 10.3% reduction | No moratorium or comeback provisions | |||
Crossroads | Option 3 | No rate change proposed | No moratorium or comeback provisions | |||
TransCanada Management's discussion and analysis 2018 | 15 |
Form 501-G Filing Option | Impact on Maximum Rates | Moratoriums and Mandatory Filing Requirements | ||||
Great Lakes | Option 1 - filing accepted by FERC | 2.0% rate reduction effective February 1, 2019 | No moratorium in effect. Comeback provision with new rates effective by October 1, 2022 | |||
GTN | Settlement approved by FERC on November 30, 2018 eliminating the requirement to file Form 501-G | A refund of US$10 million to its firm customers in 2018; a 10.0% reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021 | Moratorium on rate changes until December 31, 2021. Comeback provision with new rates effective by January 1, 2022 | |||
Northern Border | Option 1 - filing accepted by FERC | 2.0% rate reduction effective February 1, 2019; additional 2.0% rate reduction effective January 1, 2020 | No moratorium in effect. Comeback provision with new rates effective by July 1, 2024 | |||
Tuscarora | Option 1 - subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 29, 2019 | Expected to be finalized with the settlement | Expected to be finalized with the settlement | |||
Bison | Option 3 | No rate change proposed | No moratorium or comeback provisions | |||
Iroquois | Option 3 - subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 9, 2019 | Expected to reduce rates by the impact of the lower U.S. federal tax rate as shown on Form 501-G | Likely to be reaffirmed with the settlement | |||
Portland | Option 3 | No rate change proposed | No moratorium or comeback provisions | |||
North Baja | Option 1 - filing accepted by FERC | 10.8% reduction effective December 1, 2018 | No moratorium or comeback provisions |
16 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 17 |
18 | TransCanada Management's discussion and analysis 2018 |
Expected in-service date | Estimated project cost1 | Carrying value at December 31, 2018 | ||||||
(billions of $) | ||||||||
Canadian Natural Gas Pipelines | ||||||||
Canadian Mainline | 2019-2021 | 0.3 | — | |||||
NGTL System | 2019 | 2.8 | 1.4 | |||||
2020 | 1.7 | 0.2 | ||||||
2021 | 2.8 | — | ||||||
2022 | 1.3 | — | ||||||
Coastal GasLink2,3 | 2023 | 6.2 | 0.1 | |||||
Regulated maintenance capital expenditures | 2019-2021 | 1.8 | — | |||||
U.S. Natural Gas Pipelines | ||||||||
Columbia Gas | ||||||||
Mountaineer XPress | 2019 | US 3.2 | US 2.9 | |||||
Modernization II | 2019-2020 | US 1.1 | US 0.5 | |||||
Columbia Gulf | ||||||||
Gulf XPress | 2019 | US 0.6 | US 0.5 | |||||
Other capacity capital | 2019-2022 | US 0.9 | US 0.1 | |||||
Regulated maintenance capital expenditures | 2019-2021 | US 2.0 | — | |||||
Mexico Natural Gas Pipelines | ||||||||
Sur de Texas4 | 2019 | US 1.5 | US 1.4 | |||||
Villa de Reyes4 | 2019 | US 0.8 | US 0.6 | |||||
Tula4 | 2020 | US 0.7 | US 0.6 | |||||
Liquids Pipelines | ||||||||
White Spruce | 2019 | 0.2 | 0.1 | |||||
Other capacity capital | 2020 | 0.1 | — | |||||
Recoverable maintenance capital expenditures | 2019-2021 | 0.1 | — | |||||
Energy | ||||||||
Napanee | 2019 | 1.7 | 1.6 | |||||
Bruce Power – life extension5 | 2019-2023 | 2.2 | 0.6 | |||||
Other | ||||||||
Non-recoverable maintenance capital expenditures6 | 2019-2021 | 0.7 | 0.2 | |||||
32.7 | 10.8 | |||||||
Foreign exchange impact on secured projects7 | 3.9 | 2.4 | ||||||
Total secured projects (Cdn$) | 36.6 | 13.2 |
1 | Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP. |
2 | Represents 100 per cent of required capital prior to potential joint venture partners or project financing. |
3 | Carrying value is net of fourth quarter 2018 receipts from the LNG Canada participants for the reimbursement of approximately $0.5 billion of pre-FID costs pursuant to project agreements. Refer to the Significant Events section in Canadian Natural Gas Pipelines for additional details. |
4 | The CFE has recognized force majeure events for these pipelines and approved the payment of fixed capacity charges in accordance with their respective TSAs. Payments will be recognized as revenue when the pipelines are placed in service. |
5 | Reflects our proportionate share of the Unit 6 Major Component Replacement program costs, expected to be in service in 2023, and amounts to be invested under the Asset Management program through 2023. |
6 | Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital expenditures for Bruce Power and other Energy assets. |
7 | Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018. |
TransCanada Management's discussion and analysis 2018 | 19 |
Estimated project cost1 | Carrying value at December 31, 2018 | |||||
(billions of $) | ||||||
Canadian Natural Gas Pipelines | ||||||
NGTL System – Merrick | 1.9 | — | ||||
Liquids Pipelines | ||||||
Keystone XL2 | US 8.0 | US 0.6 | ||||
Heartland and TC Terminals3 | 0.9 | 0.1 | ||||
Grand Rapids Phase II3 | 0.7 | — | ||||
Keystone Hardisty Terminal3 | 0.3 | 0.1 | ||||
Energy | ||||||
Bruce Power – life extension4 | 6.0 | — | ||||
17.8 | 0.8 | |||||
Foreign exchange impact on projects under development5 | 2.9 | 0.2 | ||||
Total projects under development (Cdn$) | 20.7 | 1.0 |
1 | Amounts reflect our proportionate share of joint venture costs where applicable. |
2 | Carrying value reflects amount remaining after impairment charge recorded in 2015, along with additional amounts capitalized from January 1, 2018. |
3 | Regulatory approvals have been obtained and additional commercial support is being pursued. |
4 | Reflects our proportionate share of Major Component Replacement program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2023. |
5 | Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018. |
20 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | ||||||||||||
(millions of $, except per share amounts) | 2018 | 2017 | 2016 | |||||||||
Income | ||||||||||||
Revenues | 13,679 | 13,449 | 12,547 | |||||||||
Net income attributable to common shares | 3,539 | 2,997 | 124 | |||||||||
per common share – basic | $3.92 | $3.44 | $0.16 | |||||||||
– diluted | $3.92 | $3.43 | $0.16 | |||||||||
Comparable EBITDA | 8,563 | 7,377 | 6,647 | |||||||||
Comparable earnings | 3,480 | 2,690 | 2,108 | |||||||||
per common share | $3.86 | $3.09 | $2.78 | |||||||||
Cash flows | ||||||||||||
Net cash provided by operations | 6,555 | 5,230 | 5,069 | |||||||||
Comparable funds generated from operations | 6,522 | 5,641 | 5,171 | |||||||||
Comparable distributable cash flow | 5,885 | 4,963 | 4,482 | |||||||||
Comparable distributable cash flow per common share | $6.52 | $5.69 | $5.91 | |||||||||
Capital spending1 | 10,929 | 9,210 | 6,067 | |||||||||
Acquisitions, net of cash acquired | — | — | 13,608 | |||||||||
Proceeds from sales of assets, net of transaction costs | 614 | 4,683 | 6 | |||||||||
Reimbursement of costs related to capital projects in development | 470 | 634 | — | |||||||||
Balance sheet | ||||||||||||
Total assets | 98,920 | 86,101 | 88,051 | |||||||||
Long-term debt | 39,971 | 34,741 | 40,150 | |||||||||
Junior subordinated notes | 7,508 | 7,007 | 3,931 | |||||||||
Preferred shares | 3,980 | 3,980 | 3,980 | |||||||||
Non-controlling interests | 1,655 | 1,852 | 1,726 | |||||||||
Common shareholders' equity | 25,358 | 21,059 | 20,277 | |||||||||
Dividends declared2 | ||||||||||||
per common share | $2.76 | $2.50 | $2.26 | |||||||||
Basic common shares (millions) | ||||||||||||
– weighted average for the year | 902 | 872 | 759 | |||||||||
– issued and outstanding at end of year | 918 | 881 | 864 |
1 | Capital spending Includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity investments. |
2 | Refer to the Financial condition section on page 74 for details on common and preferred share dividends. |
TransCanada Management's discussion and analysis 2018 | 21 |
year ended December 31 | ||||||||||||
(millions of $, except per share amounts) | 2018 | 2017 | 2016 | |||||||||
Segmented earnings/(losses) | ||||||||||||
Canadian Natural Gas Pipelines | 1,250 | 1,236 | 1,307 | |||||||||
U.S. Natural Gas Pipelines | 1,700 | 1,760 | 1,190 | |||||||||
Mexico Natural Gas Pipelines | 510 | 426 | 287 | |||||||||
Liquids Pipelines | 1,579 | (251 | ) | 806 | ||||||||
Energy | 779 | 1,552 | (1,157 | ) | ||||||||
Corporate | (54 | ) | (39 | ) | (120 | ) | ||||||
Total segmented earnings | 5,764 | 4,684 | 2,313 | |||||||||
Interest expense | (2,265 | ) | (2,069 | ) | (1,998 | ) | ||||||
Allowance for funds used during construction | 526 | 507 | 419 | |||||||||
Interest income and other | (76 | ) | 184 | 103 | ||||||||
Income before income taxes | 3,949 | 3,306 | 837 | |||||||||
Income tax (expense)/recovery | (432 | ) | 89 | (352 | ) | |||||||
Net income | 3,517 | 3,395 | 485 | |||||||||
Net loss/(income) attributable to non-controlling interests | 185 | (238 | ) | (252 | ) | |||||||
Net income attributable to controlling interests | 3,702 | 3,157 | 233 | |||||||||
Preferred share dividends | (163 | ) | (160 | ) | (109 | ) | ||||||
Net income attributable to common shares | 3,539 | 2,997 | 124 | |||||||||
Net income per common share | ||||||||||||
–basic | $3.92 | $3.44 | $0.16 | |||||||||
–diluted | $3.92 | $3.43 | $0.16 |
• | a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities |
• | a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions |
• | a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform |
• | a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets |
• | $25 million of after-tax income recognized on the Bison contract terminations |
• | a $140 million after-tax impairment charge on Bison |
• | a $15 million after-tax goodwill impairment charge on Tuscarora |
• | an after-tax net loss of $4 million related to our U.S. Northeast power marketing contracts. These were excluded from Energy's comparable earnings beginning in 2018 as the wind-down of these contracts is not considered part of our underlying operations. |
22 | TransCanada Management's discussion and analysis 2018 |
• | an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform |
• | a $307 million after-tax net gain on the monetization of our U.S. Northeast power generation assets |
• | a $136 million after-tax gain on the sale of our Ontario solar assets |
• | a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets |
• | a $954 million after-tax impairment charge for the Energy East pipeline and related projects following our decision not to proceed with the project applications |
• | a $69 million after-tax charge for integration-related costs associated with the acquisition of Columbia |
• | a $28 million after-tax charge related to the maintenance and liquidation of Keystone XL assets. |
• | an $873 million after-tax loss on U.S. Northeast power generation assets held for sale |
• | $28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL project assets |
• | $273 million of after-tax costs associated with the acquisition of Columbia |
• | an after-tax charge of $42 million for Keystone XL costs related to the maintenance and liquidation of project assets |
• | a $656 million after-tax impairment of Ravenswood goodwill |
• | a $244 million after-tax impairment charge on the carrying value and settlement of our Alberta PPAs |
• | an after-tax charge of $16 million for restructuring mainly related to expected future losses under lease commitments |
• | an additional $3 million after-tax loss on the sale of TC Offshore which closed in early 2016. |
TransCanada Management's discussion and analysis 2018 | 23 |
year ended December 31 | ||||||||||||
(millions of $, except per share amounts) | 2018 | 2017 | 2016 | |||||||||
Net income attributable to common shares | 3,539 | 2,997 | 124 | |||||||||
Specific items (net of tax): | ||||||||||||
Gain on sale of Cartier Wind power facilities | (143 | ) | — | — | ||||||||
MLP regulatory liability write-off | (115 | ) | — | — | ||||||||
U.S. Tax Reform | (52 | ) | (804 | ) | — | |||||||
Net (gain)/loss on sales of U.S. Northeast power generation assets | (27 | ) | (307 | ) | 873 | |||||||
Bison contract terminations | (25 | ) | — | — | ||||||||
Bison asset impairment | 140 | — | — | |||||||||
Tuscarora goodwill impairment | 15 | — | — | |||||||||
U.S. Northeast power marketing contracts | 4 | — | — | |||||||||
Gain on sale of Ontario solar assets | — | (136 | ) | — | ||||||||
Keystone XL income tax recoveries | — | (7 | ) | (28 | ) | |||||||
Energy East impairment charge | — | 954 | — | |||||||||
Integration and acquisition related costs – Columbia | — | 69 | 273 | |||||||||
Keystone XL asset costs | — | 28 | 42 | |||||||||
Ravenswood goodwill impairment | — | — | 656 | |||||||||
Alberta PPA terminations and settlement | — | — | 244 | |||||||||
Restructuring costs | — | — | 16 | |||||||||
TC Offshore loss on sale | — | — | 3 | |||||||||
Risk management activities1 | 144 | (104 | ) | (95 | ) | |||||||
Comparable earnings | 3,480 | 2,690 | 2,108 | |||||||||
Net income per common share | $3.92 | $3.44 | $0.16 | |||||||||
Specific items (net of tax): | ||||||||||||
Gain on sale of Cartier Wind power facilities | (0.16 | ) | — | — | ||||||||
MLP regulatory liability write-off | (0.13 | ) | — | — | ||||||||
U.S. Tax Reform | (0.06 | ) | (0.92 | ) | — | |||||||
Net (gain)/loss on sales of U.S. Northeast power generation assets | (0.03 | ) | (0.34 | ) | 1.15 | |||||||
Bison contract terminations | (0.03 | ) | — | — | ||||||||
Bison asset impairment | 0.16 | — | — | |||||||||
Tuscarora goodwill impairment | 0.02 | — | — | |||||||||
U.S. Northeast power marketing contracts | 0.01 | — | — | |||||||||
Gain on sale of Ontario solar assets | — | (0.16 | ) | — | ||||||||
Keystone XL income tax recoveries | — | (0.01 | ) | (0.04 | ) | |||||||
Energy East impairment charge | — | 1.09 | — | |||||||||
Integration and acquisition related costs – Columbia | — | 0.08 | 0.37 | |||||||||
Keystone XL asset costs | — | 0.03 | 0.06 | |||||||||
Ravenswood goodwill impairment | — | — | 0.86 | |||||||||
Alberta PPA terminations and settlement | — | — | 0.32 | |||||||||
Restructuring costs | — | — | 0.02 | |||||||||
TC Offshore loss on sale | — | — | — | |||||||||
Risk management activities1 | 0.16 | (0.12 | ) | (0.12 | ) | |||||||
Comparable earnings per common share | $3.86 | $3.09 | $2.78 |
24 | TransCanada Management's discussion and analysis 2018 |
1 | year ended December 31 | ||||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||||
Liquids marketing | 71 | — | (2 | ) | |||||||
Canadian Power | 3 | 11 | 4 | ||||||||
U.S. Power | (11 | ) | 39 | 113 | |||||||
Natural Gas Storage | (11 | ) | 12 | 8 | |||||||
Interest rate | — | (1 | ) | — | |||||||
Foreign exchange | (248 | ) | 88 | 26 | |||||||
Income taxes attributable to risk management activities | 52 | (45 | ) | (54 | ) | ||||||
Total unrealized (losses)/gains from risk management activities | (144 | ) | 104 | 95 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Comparable EBITDA | 8,563 | 7,377 | 6,647 | ||||||
Adjustments: | |||||||||
Depreciation and amortization | (2,350 | ) | (2,048 | ) | (1,939 | ) | |||
Interest expense included in comparable earnings | (2,265 | ) | (2,068 | ) | (1,883 | ) | |||
Allowance for funds used during construction | 526 | 507 | 419 | ||||||
Interest income and other included in comparable earnings | 177 | 159 | 71 | ||||||
Income tax expense included in comparable earnings | (693 | ) | (839 | ) | (841 | ) | |||
Net income attributable to non-controlling interests included in comparable earnings | (315 | ) | (238 | ) | (257 | ) | |||
Preferred share dividends | (163 | ) | (160 | ) | (109 | ) | |||
Comparable earnings | 3,480 | 2,690 | 2,108 |
• | higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform |
• | higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017 |
• | higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher overall pre-tax rate base earnings, partially offset by lower incentive earnings and flow-through income taxes |
• | lower earnings from U.S. Power mainly due to the sales of our U.S. Northeast power generation assets in second quarter 2017 |
• | lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days and lower results from contracting activities. |
• | changes in comparable EBITDA described above |
• | higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018 |
• | higher interest expense primarily as a result of additional long-term debt issuances in 2018 and the full year impact of long-term debt and junior subordinated notes issuances in 2017, net of maturities, as well as lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017 |
TransCanada Management's discussion and analysis 2018 | 25 |
• | lower income tax expense primarily due to reduced income tax rates resulting from U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines. |
• | higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenue resulting from a FERC-approved rate settlement effective August 1, 2016 |
• | lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017 and the wind-down of our U.S. power marketing contracts |
• | increased earnings from Liquids Pipelines primarily due to higher uncontracted volumes on the Keystone Pipeline System, liquids marketing activities and the commencement of operations on Grand Rapids and Northern Courier |
• | higher earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days |
• | higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016. |
• | changes in comparable EBITDA described above |
• | higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt and junior subordinated notes issuances in 2017, net of maturities |
• | higher depreciation primarily from the Columbia acquisition in 2016 and projects placed in service |
• | higher AFUDC on our rate-regulated U.S. natural gas pipelines as well as on the NGTL System, Tula and Villa de Reyes, partially offset by the commercial in-service of Topolobampo and completion of Mazatlán construction |
• | higher interest income and other due to income related to the recovery of certain Coastal GasLink project costs and the termination of the Prince Rupert Gas Transmission (PRGT) project. |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Canadian Natural Gas Pipelines | 2,478 | 2,181 | 1,525 | ||||||
U.S. Natural Gas Pipelines | 5,771 | 3,830 | 1,522 | ||||||
Mexico Natural Gas Pipelines | 797 | 1,954 | 1,142 | ||||||
Liquids Pipelines | 581 | 529 | 1,137 | ||||||
Energy | 1,257 | 675 | 708 | ||||||
Corporate | 45 | 41 | 33 | ||||||
10,929 | 9,210 | 6,067 |
1 | Capital spending includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity investments. |
26 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Common shares | 1,571 | 1,339 | 1,436 | ||||||
Preferred shares | 158 | 155 | 100 |
TransCanada Management's discussion and analysis 2018 | 27 |
• | contributions from Columbia Gas and Columbia Gulf projects coming in service |
• | higher equity income from Bruce Power due to increased contract pricing |
• | growth in the average investment base for the NGTL System |
• | completion of the Napanee generating station |
• | commencement of operations on the Sur de Texas Pipeline. |
• | the dilutive impact of common shares issued in 2018 under our DRP and Corporate ATM Program and expected to be issued in 2019 under our DRP |
• | higher interest expense as a result of long-term debt issuances, net of maturities, and lower capitalized interest after placing assets in service |
• | the sale of our interests in the Cartier Wind power facilities |
• | the expected sale of our Coolidge generating station |
• | the uncertain impact of recent U.S. Tax Reform legislation and proposed regulations on the cost of financing certain of our U.S. operations. |
28 | TransCanada Management's discussion and analysis 2018 |
• | wholly-owned natural gas pipelines – 81,500 km (50,500 miles); and |
• | partially-owned natural gas pipelines – 11,100 km (7,000 miles). |
Strategy at a glance |
Optimizing the value of our existing natural gas pipeline systems, while responding to the changing flow patterns of natural gas in North America, is a top priority. We are also pursuing new pipeline opportunities to add incremental value to our business. |
Our key areas of focus include: |
• expansion and extension of our existing large North American natural gas pipeline footprint • connections to new and growing industrial and electric power generation markets and LDCs • expanding our systems in key locations and building development projects to provide connectivity to LNG export terminals on the west coast of Canada and the Gulf of Mexico • connections to growing Canadian and U.S. shale gas and other supplies • additional new pipeline developments within Mexico. |
Each of these areas plays a critical role in meeting the transportation requirements for supply of and demand for natural gas in North America. |
• | placed approximately $0.6 billion of projects in service |
• | announced four new expansion programs on our NGTL System totaling $4.1 billion with in-service dates between 2019 and 2022 |
• | received an amending order and Certificate of Public Convenience and Necessity (CPCN) from the NEB approving construction of the North Montney Mainline facilities and guidance on related tolling matters |
• | received NEB approval on the NGTL 2018-2019 Revenue Requirement Settlement (2018-2019 Settlement), as filed |
• | received the NEB Decision on the Canadian Mainline 2018-2020 Tolls Application (NEB 2018 Decision) approving all elements of the filing except for the amortization period of the LTAA |
• | secured 670 TJ/d (625 MMcf/d) of new natural gas transportation contracts on the Canadian Mainline for North Bay Junction Long Term Fixed Price (NBJ LTFP) service from the WCSB to markets in Ontario, Québec, New Brunswick, Nova Scotia and the Northeastern U.S. |
• | proceeding with the estimated $6.2 billion Coastal GasLink pipeline project. |
• | placed in service in 2018 and early 2019 approximately US$5.8 billion of projects including Leach XPress, WB XPress, Cameron Access and partial in-service of Mountaineer XPress |
• | originated an additional US$0.5 billion of growth projects |
• | filed Form 501-Gs and uncontested rate settlements in response to the 2018 FERC Actions, which impacted rates for our U.S. natural gas pipelines and storage assets to varying degrees. Refer to the 2018 FERC Actions section for more detail. |
• | placed Topolobampo in operational service |
• | continued construction on our Sur de Texas, Villa de Reyes and Tula pipeline projects. |
TransCanada Management's discussion and analysis 2018 | 29 |
30 | TransCanada Management's discussion and analysis 2018 |
• | natural gas-fired electric-power generation |
• | petrochemical and industrial facilities |
• | Alberta oil sands |
• | exports to Mexico to fuel power generation facilities. |
TransCanada Management's discussion and analysis 2018 | 31 |
32 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 33 |
Length | Description | Effective ownership | |||||||
Canadian pipelines | |||||||||
1 | NGTL System | 24,568 km (15,266 miles) | Receives, transports and delivers natural gas within Alberta and B.C., and connects with the Canadian Mainline, Foothills system and third-party pipelines. | 100 | % | ||||
2 | Canadian Mainline | 14,082 km (8,750 miles) | Transports natural gas from the Alberta/Saskatchewan border and the Ontario/U.S. border to serve eastern Canada and interconnects to the U.S. | 100 | % | ||||
3 | Foothills | 1,241 km (771 miles) | Transports natural gas from central Alberta to the U.S. border for export to the U.S. Midwest, Pacific Northwest, California and Nevada. | 100 | % | ||||
4 | Trans Québec & Maritimes (TQM) | 574 km (357 miles) | Connects with the Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montréal to Québec City corridor, and interconnects with the Portland pipeline system. | 50 | % | ||||
5 | Ventures LP | 161 km (100 miles) | Transports natural gas to the oil sands region near Fort McMurray, Alberta. It also includes a 27 km (17 miles) pipeline supplying natural gas to a petrochemical complex at Joffre, Alberta. | 100 | % | ||||
* | Great Lakes Canada | 60 km (37 miles) | Transports natural gas from the Great Lakes system in the U.S. to a point near Dawn, Ontario through a connection at the U.S. border underneath the St. Clair River. | 100 | % | ||||
U.S. pipelines and gas storage assets | |||||||||
6 | ANR | 15,075 km (9,367 miles) | Transports natural gas from various supply basins to markets throughout the U.S. Midwest and Gulf Coast. | 100 | % | ||||
6a | ANR Storage | 250 Bcf | Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key mid-western markets. | ||||||
7 | Bison | 488 km (303 miles) | Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 25.5 per cent of the system through our interest in TC PipeLines, LP. | 25.5 | % | ||||
8 | Columbia Gas | 18,525 km (11,511 miles) | Transports natural gas from supply primarily in the Appalachian Basin to markets and pipeline interconnects throughout the U.S. Northeast. | 100 | % | ||||
8a | Columbia Storage | 285 Bcf | Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key eastern markets. We also own a 50 per cent interest in the 12 Bcf Hardy Storage facility. | 100 | % | ||||
* | Midstream | 295 km (183 miles) | Provides infrastructure between the producer upstream well-head and the downstream (interstate pipeline and distribution) sector and includes a 47.5 per cent interest in Pennant Midstream. | 100 | % | ||||
9 | Columbia Gulf | 5,419 km (3,367 miles) | Transports natural gas to various markets and pipeline interconnects in the southern U.S. and Gulf Coast. | 100 | % | ||||
10 | Crossroads | 325 km (202 miles) | Interstate natural gas pipeline operating in Indiana and Ohio with multiple interconnects to other pipelines. | 100 | % | ||||
11 | Gas Transmission Northwest (GTN) | 2,216 km (1,377 miles) | Transports WCSB and Rockies natural gas to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 25.5 per cent of the system through our interest in TC PipeLines, LP. | 25.5 | % | ||||
12 | Great Lakes | 3,404 km (2,115 miles) | Connects with the Canadian Mainline near Emerson, Manitoba and to Great Lakes Canada near St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada and the U.S. Upper Midwest. We effectively own 65.4 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 25.5 per cent interest in TC PipeLines, LP. | 65.4 | % | ||||
34 | TransCanada Management's discussion and analysis 2018 |
Length | Description | Effective ownership | |||||||
13 | Iroquois | 669 km (416 miles) | Connects with the Canadian Mainline and serves markets in New York. We effectively own 13.2 per cent of the system through a 0.7 per cent direct ownership and our 25.5 per cent interest in TC PipeLines, LP. | 13.2 | % | ||||
14 | Millennium | 407 km (253 miles) | Transports natural gas primarily sourced from the Marcellus shale play to markets across southern New York and the lower Hudson Valley, as well as to New York City through its pipeline interconnections. | 47.5 | % | ||||
15 | North Baja | 138 km (86 miles) | Transports natural gas between Arizona and California, and connects with a third-party pipeline on the California/Mexico border. We effectively own 25.5 per cent of the system through our interest in TC PipeLines, LP. | 25.5 | % | ||||
16 | Northern Border | 2,272 km (1,412 miles) | Transports WCSB, Bakken and Rockies natural gas from connections with Foothills and Bison to U.S. Midwest markets. We effectively own 12.7 per cent of the system through our 25.5 per cent interest in TC PipeLines, LP. | 12.7 | % | ||||
17 | Portland | 475 km (295 miles) | Connects with TQM near East Hereford, Québec to deliver natural gas to customers in the U.S. Northeast and Canadian Maritimes. We effectively own 15.7 per cent of the system through our 25.5 per cent interest in TC PipeLines, LP. | 15.7 | % | ||||
18 | Tuscarora | 491 km (305 miles) | Transports natural gas from GTN at Malin, Oregon to markets in northeastern California and northwestern Nevada. We effectively own 25.5 per cent of the system through our interest in TC PipeLines, LP. | 25.5 | % | ||||
Mexico pipelines | |||||||||
19 | Guadalajara | 310 km (193 miles) | Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco. | 100 | % | ||||
20 | Mazatlán | 430 km (267 miles) | Transports natural gas from El Oro to Mazatlán, in the State of Sinaloa. Connects to the Topolobampo Pipeline at El Oro. | 100 | % | ||||
21 | Tamazunchale | 370 km (230 miles) | Transports natural gas from Naranjos, Veracruz to Tamazunchale and on to El Sauz, Querétaro in central Mexico. | 100 | % | ||||
22 | Topolobampo | 560 km (348 miles) | Transports natural gas to El Oro and Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Encino, Chihuahua, and El Oro, Sinaloa. | 100 | % | ||||
Under construction | |||||||||
Canadian pipelines | |||||||||
23 | North Montney | 206 km** (128 miles) | An extension of the NGTL System to receive natural gas from the North Montney gas producing region and connect to NGTL's existing Groundbirch Mainline. | 100% | |||||
* | NGTL 2019 Facilities | 160 km** (99 miles) | An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by November 2019. | 100% | |||||
24 | Coastal GasLink | 670 km** (416 miles) | A greenfield project to deliver natural gas from the Montney gas producing region to LNG Canada's liquefaction facility under construction near Kitimat, B.C. | 100% | |||||
U.S. pipelines | |||||||||
25 | Mountaineer XPress - 45 per cent in-service in January 2019 (192 km or 119 miles) | 275 km** (171 miles) | A Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system and to the Leach interconnect with Columbia Gulf. | 100% | |||||
TransCanada Management's discussion and analysis 2018 | 35 |
Under construction (continued) | Length | Description | Effective ownership | |||||
Mexico pipelines | ||||||||
26 | Tula | 324 km** (201 miles) | The pipeline will originate in Tuxpan in the state of Veracruz, where it will receive natural gas from Sur de Texas and interconnect with Villa de Reyes at Tula to supply natural gas to CFE combined-cycle power generating facilities in central Mexico. | 100% | ||||
27 | Villa de Reyes | 420 km** (261 miles) | This bi-directional pipeline will transport natural gas from Tula, Hidalgo to Villa de Reyes, San Luis Potosi, connecting to the Tamazunchale and Tula pipelines including a lateral to the Salamanca industrial complex in Guanajuato. | 100% | ||||
28 | Sur de Texas | 775 km** (482 miles) | The pipeline will begin offshore in the Gulf of Mexico at the border near Brownsville, Texas with landfalls at Altamira, Tamaulipas and Tuxpan, Veracruz, connecting with the Tamazunchale and Tula pipelines and other third-party facilities. | 60% | ||||
Permitting and pre-construction phase | ||||||||
Canadian pipelines | ||||||||
* | NGTL 2020 Facilities | 120 km** (75 miles) | An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by November 2020. | 100% | ||||
* | NGTL 2021 Facilities | 375 km** (233 miles) | An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by November 2021. | 100% | ||||
* | NGTL 2022 Facilities | 197 km** (122 miles) | An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by April 2022. | 100% | ||||
U.S. pipelines | ||||||||
* | Buckeye XPress | 103 km** (64 miles) | A Columbia Gas project designed to upgrade and replace existing pipeline and compression facilities in Ohio to transport incremental supply from the Marcellus and Utica shale plays to points along the system. | 100% | ||||
In development | ||||||||
Canadian pipelines | ||||||||
29 | Merrick Mainline | 260 km** (161 miles) | To deliver natural gas from NGTL's existing Groundbirch Mainline near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C. | 100% | ||||
* ** | Facilities and some pipelines are not shown on the map. Final pipe lengths are subject to change during construction and/or final design considerations. |
36 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 37 |
38 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
NGTL System | 1,197 | 996 | 968 | ||||||
Canadian Mainline | 1,073 | 1,043 | 1,105 | ||||||
Other Canadian pipelines1 | 109 | 105 | 109 | ||||||
Comparable EBITDA | 2,379 | 2,144 | 2,182 | ||||||
Depreciation and amortization | (1,129 | ) | (908 | ) | (875 | ) | |||
Comparable EBIT and segmented earnings | 1,250 | 1,236 | 1,307 |
1 | Includes results from Foothills, Ventures LP, Great Lakes Canada, and our share of equity income from our investment in TQM, as well as general and administrative and business development costs related to our Canadian Natural Gas Pipelines. |
TransCanada Management's discussion and analysis 2018 | 39 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Net income | |||||||||
NGTL System | 398 | 352 | 318 | ||||||
Canadian Mainline | 182 | 199 | 208 | ||||||
Average investment base | |||||||||
NGTL System | 9,669 | 8,385 | 7,451 | ||||||
Canadian Mainline | 3,828 | 4,184 | 4,441 |
40 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 41 |
42 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 43 |
year ended December 31 | |||||||||
(millions of US$, unless otherwise noted) | 2018 | 2017 | 2016 | ||||||
Columbia Gas1 | 873 | 623 | 269 | ||||||
ANR | 508 | 400 | 321 | ||||||
TC PipeLines, LP2,3 | 138 | 118 | 118 | ||||||
Midstream1 | 122 | 93 | 40 | ||||||
Columbia Gulf1 | 120 | 76 | 25 | ||||||
Great Lakes3,4 | 97 | 64 | 60 | ||||||
Other U.S. pipelines2,3,5 | 68 | 80 | 71 | ||||||
Non-controlling interests6 | 415 | 359 | 365 | ||||||
Comparable EBITDA | 2,341 | 1,813 | 1,269 | ||||||
Depreciation and amortization | (511 | ) | (453 | ) | (322 | ) | |||
Comparable EBIT | 1,830 | 1,360 | 947 | ||||||
Foreign exchange impact | 541 | 410 | 310 | ||||||
Comparable EBIT (Cdn$) | 2,371 | 1,770 | 1,257 | ||||||
Specific items: | |||||||||
Bison asset impairment7 | (722 | ) | — | — | |||||
Tuscarora goodwill impairment7 | (79 | ) | — | — | |||||
Bison contract terminations7 | 130 | — | — | ||||||
Integration and acquisition related costs – Columbia | — | (10 | ) | (63 | ) | ||||
TC Offshore loss on sale | — | — | (4 | ) | |||||
Segmented earnings (Cdn$) | 1,700 | 1,760 | 1,190 |
1 | We completed the acquisition of Columbia on July 1, 2016. Results reflect our effective ownership in these assets from that date. |
2 | Results reflect our earnings from TC PipeLines, LP's ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, Portland, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP. Results from Northern Border and Iroquois reflect our share of equity income from these investments. We acquired additional interests in Iroquois of 4.87 per cent on March 31, 2016 and 0.65 per cent on May 1, 2016. TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois on June 1, 2017. On January 1, 2016, we sold a 49.9 per cent direct interest in Portland to TC PipeLines, LP and the remaining 11.81 per cent to TC PipeLines, LP on June 1, 2017. |
3 | TC PipeLines, LP periodically conducted ATM issuances which decreased our ownership in TC PipeLines, LP. Effective March 2018, this program ceased to be utilized. Our ownership interest in TC PipeLines, LP was 25.5 per cent as at December 31, 2018 compared to 25.7 per cent and 26.8 per cent at December 31, 2017 and December 31, 2016, respectively. |
4 | Represents our 53.6 per cent direct interest in Great Lakes. The remaining 46.4 per cent is held by TC PipeLines, LP. |
5 | Results reflect earnings from our direct ownership interests in Crossroads, as well as Iroquois and Portland until June 1, 2017, our effective ownership in Millennium and Hardy Storage, and general and administrative and business development costs related to U.S. natural gas pipelines. |
6 | Results reflect earnings attributable to portions of TC PipeLines, LP, Portland (until June 1, 2017) and Columbia Pipeline Partners LP (CPPL) (until February 17, 2017) that we do not own. |
7 | These amounts were recorded in TC PipeLines, LP. The pre-tax impact to us is 25.5 per cent of these amounts net of non-controlling interests. |
44 | TransCanada Management's discussion and analysis 2018 |
• | a $722 million non-cash asset impairment charge related to Bison |
• | a $79 million non-cash goodwill impairment charge related to Tuscarora |
• | $130 million of termination payments received on two of Bison’s transportation contracts, which was recorded in Revenues. |
• | increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and improved commodity prices and throughput volumes in Midstream |
• | increased earnings due to the amortization of the net regulatory liabilities that were recorded at the end of 2017, partially offset by a reduction in certain rates on Columbia Gas as a result of U.S. Tax Reform |
• | a US$10 million refund from GTN to its recourse rate customers as per the 2018 GTN Settlement. Refer to the 2018 FERC Actions section for additional details. |
• | a full year contribution from the Columbia assets acquired in 2016 |
• | higher ANR transportation revenue resulting from a FERC-approved rate settlement, effective August 1, 2016. |
TransCanada Management's discussion and analysis 2018 | 45 |
46 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of US$, unless otherwise noted) | 2018 | 2017 | 2016 | ||||||
Topolobampo | 172 | 157 | 81 | ||||||
Tamazunchale | 127 | 112 | 105 | ||||||
Mazatlán | 78 | 65 | 5 | ||||||
Guadalajara | 71 | 68 | 67 | ||||||
Sur de Texas1 | 16 | 8 | — | ||||||
Other | 4 | (11 | ) | (8 | ) | ||||
Comparable EBITDA | 468 | 399 | 250 | ||||||
Depreciation and amortization | (75 | ) | (72 | ) | (35 | ) | |||
Comparable EBIT | 393 | 327 | 215 | ||||||
Foreign exchange impact | 117 | 99 | 72 | ||||||
Comparable EBIT and segmented earnings (Cdn$) | 510 | 426 | 287 |
1 | Represents our 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. |
TransCanada Management's discussion and analysis 2018 | 47 |
• | higher revenues from operations as a result of changes in timing of revenue recognition |
• | incremental earnings from a CRE tariff increase |
• | the $12 million impairment of our equity investment in TransGas in 2017, recorded in Other above |
• | equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The interest expense on this inter-affiliate loan is fully offset in Interest income and other in the Corporate segment. |
• | incremental earnings from Topolobampo beginning July 2016 and Mazatlán beginning December 2016 |
• | equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada which is fully offset in Interest income and other in the Corporate segment. |
48 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 49 |
50 | TransCanada Management's discussion and analysis 2018 |
Strategy at a glance |
• focus on accessing and delivering growing North American liquids supply to key markets by expanding our crude oil pipelines infrastructure to deliver directly from supply regions seamlessly along a contiguous path to market |
• maximizing the value from our current operating assets and securing organic growth around these assets |
• positioning our business development activities to identify and capture attractive organic growth and acquisition opportunities |
• expand transportation service offerings to other areas of the liquids value chain including ancillary services such as short- and long-term storage of liquids, which complement our pipeline transportation infrastructure. |
• | commenced construction on the White Spruce pipeline |
• | obtained shipper commitments on all available Keystone XL project capacity |
• | completed construction of an additional one million barrels of crude oil storage at our Cushing Terminal in Oklahoma. |
TransCanada Management's discussion and analysis 2018 | 51 |
52 | TransCanada Management's discussion and analysis 2018 |
Length | Description | Ownership | ||||||
Liquids pipelines | ||||||||
1 | Keystone Pipeline System | 4,324 km (2,687 miles) | Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka, Illinois, Cushing, Oklahoma, and the U.S. Gulf Coast. | 100 | % | |||
2 | Marketlink | Transports crude oil from Cushing, Oklahoma to the U.S. Gulf Coast on facilities that form part of the Keystone Pipeline System. | 100 | % | ||||
3 | Grand Rapids | 460 km (287 miles) | Transports crude oil from the producing area northwest of Fort McMurray, Alberta to the Edmonton/Heartland, Alberta market region. | 50 | % | |||
4 | Northern Courier | 90 km (56 miles) | Transports bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta. | 100 | % | |||
Under construction | ||||||||
5 | White Spruce | 72 km (45 miles) | To transport crude oil from the Canadian Natural Resources Limited's Horizon facility in northeast Alberta into the Grand Rapids pipeline. | 100 | % | |||
In development | ||||||||
6 | Keystone XL | 1,947 km (1,210 miles) | To transport crude oil from Hardisty, Alberta to Steele City, Nebraska to expand capacity of the Keystone Pipeline System. | 100 | % | |||
7 | Keystone Hardisty Terminal | Crude oil terminal located at Hardisty, Alberta. | 100 | % | ||||
8 | Bakken Marketlink | To transport crude oil from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma and the U.S. Gulf Coast on facilities that form part of the Keystone Pipeline System. | 100 | % | ||||
9 10 | Heartland and TC Terminals | 200 km (125 miles) | Terminal and pipeline facilities to transport crude oil from the Edmonton/Heartland, Alberta region to Hardisty, Alberta. | 100 | % | |||
11 | Grand Rapids Phase II | 460 km (286 miles) | Expansion of Grand Rapids to transport additional crude oil from the producing area northwest of Fort McMurray, Alberta to the Edmonton/Heartland, Alberta market region. | 50 | % | |||
TransCanada Management's discussion and analysis 2018 | 53 |
54 | TransCanada Management's discussion and analysis 2018 |
• | expanding and leveraging our existing infrastructure |
• | protecting and optimizing the value of our existing assets |
• | expanding the transportation services that we offer and extend into adjacent jurisdictions |
• | extending into emerging growth opportunities. |
TransCanada Management's discussion and analysis 2018 | 55 |
56 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Keystone Pipeline System | 1,443 | 1,283 | 1,155 | ||||||
Intra-Alberta pipelines | 160 | 33 | — | ||||||
Liquids marketing and other | 246 | 32 | (3 | ) | |||||
Comparable EBITDA | 1,849 | 1,348 | 1,152 | ||||||
Depreciation and amortization | (341 | ) | (309 | ) | (292 | ) | |||
Comparable EBIT | 1,508 | 1,039 | 860 | ||||||
Specific items: | |||||||||
Energy East impairment charge | — | (1,256 | ) | — | |||||
Keystone XL asset costs | — | (34 | ) | (52 | ) | ||||
Risk management activities | 71 | — | (2 | ) | |||||
Segmented earnings/(losses) | 1,579 | (251 | ) | 806 | |||||
Comparable EBIT denominated as follows: | |||||||||
Canadian dollars | 370 | 255 | 223 | ||||||
U.S. dollars | 876 | 604 | 482 | ||||||
Foreign exchange impact | 262 | 180 | 155 | ||||||
Comparable EBIT | 1,508 | 1,039 | 860 |
• | a $1,256 million pre-tax impairment charge for the Energy East pipeline and related projects |
• | $34 million (2016 – $52 million) of pre-tax costs related to Keystone XL for the maintenance and liquidation of project assets which were expensed pending further advancement of the project. |
• | higher contracted and uncontracted volumes on the Keystone Pipeline System |
• | higher contribution from liquids marketing activities from improved margins and volumes |
• | incremental contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017 |
• | lower business development costs as a result of capitalizing Keystone XL expenditures in 2018. |
• | higher uncontracted volumes on the Keystone Pipeline System |
• | a higher contribution from liquids marketing activities from improved margins and volumes |
• | contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017 |
• | higher business development activities, including advancement of Keystone XL for which costs were expensed |
• | a weaker U.S. dollar which had a negative impact on the Canadian dollar equivalent comparable earnings from our U.S. operations. |
TransCanada Management's discussion and analysis 2018 | 57 |
58 | TransCanada Management's discussion and analysis 2018 |
Strategy at a glance |
• maximize the value of our portfolio of Energy assets through safe and optimized operations |
• disciplined execution of capital programs |
• pursue growth in contracted power infrastructure with a focus on our core markets of Alberta and Ontario. |
• | advanced the life extension program at Bruce Power with the final Unit 6 Major Component Replacement (MCR) cost and schedule duration estimate verified by the IESO. The Unit 6 MCR outage is scheduled to begin in early 2020 |
• | completed the sale of our interests in the Cartier Wind power facilities |
• | entered into an agreement to sell our Coolidge power generation station for approximately US$465 million |
• | completed monetization of the U.S. Northeast power retail contracts as part of the continued wind-down of our U.S. Northeast power marketing business |
• | construction is substantially complete on the Napanee natural gas-fired power plant with expected in-service in second quarter 2019. |
TransCanada Management's discussion and analysis 2018 | 59 |
60 | TransCanada Management's discussion and analysis 2018 |
Generating capacity (MW) | Type of fuel | Description | Ownership | ||||||||||
Power 6,615 MW of power generation capacity (including facilities under construction and held for sale) | |||||||||||||
Western Power 1,023 MW of power generation capacity in Alberta and Arizona (including asset held for sale) | |||||||||||||
1 | Bear Creek | 100 | natural gas | Cogeneration plant in Grande Prairie, Alberta. | 100 | % | |||||||
2 | Carseland | 95 | natural gas | Cogeneration plant in Carseland, Alberta. | 100 | % | |||||||
3 | Mackay River | 207 | natural gas | Cogeneration plant in Fort McMurray, Alberta. | 100 | % | |||||||
4 | Redwater | 46 | natural gas | Cogeneration plant in Redwater, Alberta. | 100 | % | |||||||
Eastern Power 2,498 MW of power generation capacity (including facility under construction) | |||||||||||||
5 | Bécancour | 550 | natural gas | Cogeneration plant in Trois-Rivières, Québec. Power sold under a 20-year PPA with Hydro-Québec which expires in 2026. Steam sold to an industrial customer. Power generation has been suspended since 2008. We continue to receive capacity payments while generation is suspended. | 100 | % | |||||||
6 | Grandview | 90 | natural gas | Cogeneration plant in Saint John, New Brunswick. Power sold under a 20-year tolling agreement for 100 per cent of heat and electricity output with Irving Oil which expires in 2024. | 100 | % | |||||||
7 | Halton Hills | 683 | natural gas | Combined-cycle plant in Halton Hills, Ontario. Power sold under a 20-year Clean Energy Supply contract with the IESO which expires in 2030. | 100 | % | |||||||
8 | Portlands Energy | 2751 | natural gas | Combined-cycle plant in Toronto, Ontario. Power sold under a 20-year Clean Energy Supply contract with the IESO which expires in 2029. | 50 | % | |||||||
Bruce Power 3,094 MW of power generation capacity | |||||||||||||
9 | Bruce Power | 3,0941 | nuclear | Eight operating reactors in Tiverton, Ontario. Bruce Power leases the eight nuclear facilities from OPG. | 48.3 | % | |||||||
Unregulated natural gas storage 118 Bcf of non-regulated natural gas storage capacity | |||||||||||||
10 | Crossfield | 68 Bcf | Underground facility connected to the NGTL System near Crossfield, Alberta. | 100 | % | ||||||||
11 | Edson | 50 Bcf | Underground facility connected to the NGTL System near Edson, Alberta. | 100 | % | ||||||||
Under construction | |||||||||||||
12 | Napanee | 900 | natural gas | Combined-cycle plant in Greater Napanee, Ontario. Power sold under a 20-year Clean Energy Supply contract with the IESO which expires 20 years from in-service date. Expected in-service date is second quarter 2019. | 100 | % | |||||||
Asset held for sale | |||||||||||||
13 | Coolidge | 575 | natural gas | Simple-cycle peaking facility in Coolidge, Arizona. Power sold under a 20-year PPA with the Salt River Project Agricultural Improvements & Power District which expires in 2031. | 100 | % |
1 | Our share of power generation capacity. |
TransCanada Management's discussion and analysis 2018 | 61 |
• | Power |
• | Natural Gas Storage (Canadian, non-regulated). |
62 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 63 |
year ended December 31 | |||||||||
(millions of Canadian $, unless otherwise noted) | 2018 | 2017 | 2016 | ||||||
Western and Eastern Power1,2 | 428 | 444 | 423 | ||||||
Bruce Power2 | 311 | 434 | 293 | ||||||
U.S. Power (US$)3 | — | 100 | 394 | ||||||
Foreign exchange impact on U.S. Power | — | 30 | 128 | ||||||
Natural Gas Storage and other | 27 | 55 | 58 | ||||||
Business Development4 | (14 | ) | (33 | ) | (15 | ) | |||
Comparable EBITDA | 752 | 1,030 | 1,281 | ||||||
Depreciation and amortization | (119 | ) | (151 | ) | (302 | ) | |||
Comparable EBIT | 633 | 879 | 979 | ||||||
Specific items: | |||||||||
Gain on sale of Cartier Wind power facilities | 170 | — | — | ||||||
U.S. Northeast power marketing contracts | (5 | ) | — | — | |||||
Net gain/(loss) on sales of U.S. Northeast power generation assets | — | 484 | (844 | ) | |||||
Gain on sale of Ontario solar assets | — | 127 | — | ||||||
Ravenswood goodwill impairment | — | — | (1,085 | ) | |||||
Alberta PPA terminations and settlement | — | — | (332 | ) | |||||
Risk management activities | (19 | ) | 62 | 125 | |||||
Segmented earnings/(losses) | 779 | 1,552 | (1,157 | ) |
1 | Includes losses from the Alberta PPAs up to March 2016 when the PPAs were terminated. |
2 | Includes our share of equity income from our investments in Portlands Energy and Bruce Power. |
3 | In second quarter 2017, we completed the sales of our U.S. Northeast power generation assets. |
4 | Includes a $21 million impairment charge in 2017 related to obsolete equipment. |
64 | TransCanada Management's discussion and analysis 2018 |
• | a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities. Refer to the Significant events section for more details |
• | a pre-tax net loss of $5 million in 2018 related to our U.S. Northeast power marketing contracts, including a gain in first quarter 2018 on the sale of our retail contracts. These results have been excluded from Energy's comparable earnings in 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020. Refer to the Significant events section for more details on the sale of our retail contracts |
• | a pre-tax net gain in 2017 of $484 million (2016 – loss of $844 million) related to the monetization of our U.S. Northeast power generation assets which included a $715 million gain on the sale of TC Hydro, a loss of $211 million (2016 – $829 million) on the sale of the thermal and wind package and $20 million (2016 – $15 million) of pre-tax disposition costs |
• | a pre-tax gain in 2017 of $127 million related to the sale of our Ontario solar assets |
• | a $1,085 million pre-tax impairment of Ravenswood goodwill in 2016. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value |
• | a $332 million pre-tax charge in 2016 which included a $211 million impairment charge on the carrying value of our Alberta PPAs, a $29 million impairment of our equity investment in ASTC Power Partnership, and a $92 million loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the PPA terminations |
• | unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks, as noted in the table below: |
Risk management activities | |||||||||
(millions of $, pre-tax) | 2018 | 2017 | 2016 | ||||||
Canadian Power | 3 | 11 | 4 | ||||||
U.S. Power | (11 | ) | 39 | 113 | |||||
Natural Gas Storage | (11 | ) | 12 | 8 | |||||
Total unrealized (losses)/gains from risk management activities | (19 | ) | 62 | 125 |
• | lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017 |
• | decreased earnings from Bruce Power primarily due to lower volumes resulting from higher outage days and lower results from contracting activities. Additional financial and operating information on Bruce Power is provided below |
• | decreased Natural Gas Storage results due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities and resulted in lower realized natural gas storage price spreads |
• | lower earnings from Western and Eastern Power due to the sales of our Ontario solar assets in December 2017 and our interest in the Cartier Wind power facilities in October 2018, partially offset by higher Western Power realized margins on higher generation volumes. |
• | lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017 and the wind-down of our U.S. power marketing contracts |
• | increased earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days |
• | higher earnings from Western and Eastern Power primarily due to the termination of the Alberta PPAs. |
TransCanada Management's discussion and analysis 2018 | 65 |
year ended December 31 | ||||||||||||
(millions of $, unless otherwise noted) | 2018 | 2017 | 2016 | |||||||||
Equity income included in comparable EBITDA and EBIT comprised of: | ||||||||||||
Revenues1 | 1,526 | 1,626 | 1,491 | |||||||||
Operating expenses | (852 | ) | (846 | ) | (870 | ) | ||||||
Depreciation and other | (363 | ) | (346 | ) | (328 | ) | ||||||
Comparable EBITDA and EBIT2 | 311 | 434 | 293 | |||||||||
Bruce Power – other information | ||||||||||||
Plant availability3 | 87 | % | 90 | % | 83 | % | ||||||
Planned outage days | 280 | 221 | 415 | |||||||||
Unplanned outage days | 92 | 49 | 76 | |||||||||
Sales volumes (GWh)2 | 23,486 | 24,368 | 22,178 | |||||||||
Realized sales price per MWh4 | $67 | $67 | $68 |
1 | Net of amounts recorded to reflect operating cost efficiencies shared with the IESO. |
2 | Represents our 48.3 per cent (2017 – 48.4 per cent; 2016 – 48.5 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation. |
3 | The percentage of time the plant was available to generate power, regardless of whether it was running. |
4 | Calculation based on actual and deemed generation. Realized sales price per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues. |
66 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 67 |
68 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Comparable EBITDA and EBIT | (59 | ) | (21 | ) | 18 | ||||
Specific items: | |||||||||
Foreign exchange gain – inter-affiliate loan1 | 5 | 63 | — | ||||||
Integration and acquisition related costs – Columbia | — | (81 | ) | (116 | ) | ||||
Restructuring costs | — | — | (22 | ) | |||||
Segmented losses | (54 | ) | (39 | ) | (120 | ) |
1 | Reported in Income from equity investments on the Consolidated statement of income. |
TransCanada Management's discussion and analysis 2018 | 69 |
(millions of $) | Employee Severance | Lease Commitments | Total | ||||||
Restructuring liability as at December 31, 2016 | 36 | 63 | 99 | ||||||
Restructuring charges1 | — | 6 | 6 | ||||||
Accretion expense | — | 1 | 1 | ||||||
Cash payments | (27 | ) | (17 | ) | (44 | ) | |||
Restructuring liability as at December 31, 2017 | 9 | 53 | 62 | ||||||
Restructuring charges1 | — | 42 | 42 | ||||||
Accretion expense | — | 1 | 1 | ||||||
Cash payments | (9 | ) | (15 | ) | (24 | ) | |||
Restructuring Liability as at December 31, 2018 | — | 81 | 81 |
1 | At December 31, 2018, we recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are expected to be recovered through regulatory and tolling structures in future periods (2017 – $3 million and $3 million, respectively). |
year ended December 31 | ||||||||
(millions of $) | 2018 | 2017 | 2016 | |||||
Interest on long-term debt and junior subordinated notes | ||||||||
Canadian dollar-denominated | (549 | ) | (494 | ) | (452 | ) | ||
U.S. dollar-denominated | (1,325 | ) | (1,269 | ) | (1,127 | ) | ||
Foreign exchange impact | (394 | ) | (379 | ) | (366 | ) | ||
(2,268 | ) | (2,142 | ) | (1,945 | ) | |||
Other interest and amortization expense | (121 | ) | (99 | ) | (114 | ) | ||
Capitalized interest | 124 | 173 | 176 | |||||
Interest expense included in comparable earnings | (2,265 | ) | (2,068 | ) | (1,883 | ) | ||
Specific items: | ||||||||
Integration and acquisition related costs – Columbia | — | — | (115 | ) | ||||
Risk management activities | — | (1 | ) | — | ||||
Interest expense | (2,265 | ) | (2,069 | ) | (1,998 | ) |
• | long-term debt and junior subordinated note issuances in 2018 and 2017, net of maturities. See the Financial condition section for further details on long-term debt |
• | lower capitalized interest primarily due to the completion of Grand Rapids and Northern Courier in the second half of 2017, partially offset by ongoing construction at Napanee and the recommencement of capitalization of Keystone XL costs in 2018 |
• | higher levels of short-term borrowing |
• | final repayment of the Columbia acquisition bridge facilities in June 2017 resulting in lower interest and debt amortization expense. |
• | long-term debt and junior subordinated notes issuances in 2017 and 2016, net of maturities. Refer to the Financial condition section for further details on long-term debt |
• | debt assumed in the acquisition of Columbia on July 1, 2016 |
• | lower amortization expense on debt issuance costs related to the Columbia acquisition bridge facilities, which were fully repaid in June 2017 |
• | higher foreign exchange on interest expense related to higher levels of U.S. dollar-denominated debt |
• | the specific item of $115 million in 2016 included the dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition and $6 million of other acquisition related costs. |
70 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Allowance for funds used during construction | |||||||||
Canadian dollar-denominated | 103 | 174 | 181 | ||||||
U.S. dollar-denominated | 326 | 259 | 181 | ||||||
Foreign exchange impact | 97 | 74 | 57 | ||||||
Allowance for funds used during construction | 526 | 507 | 419 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Interest income and other included in comparable earnings | 177 | 159 | 71 | ||||||
Specific items: | |||||||||
Foreign exchange loss – inter-affiliate loan | (5 | ) | (63 | ) | — | ||||
Integration and acquisition related costs – Columbia | — | — | 6 | ||||||
Risk management activities | (248 | ) | 88 | 26 | |||||
Interest income and other | (76 | ) | 184 | 103 |
• | unrealized losses on risk management activities in 2018 compared to unrealized gains in 2017, reflecting the strengthening of the U.S. dollar at the end of 2018. These amounts have been excluded from comparable earnings |
• | higher interest income combined with a lower foreign exchange loss related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively, resulting in no impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings |
• | realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income |
• | lower recovery in 2018 related to carrying charges on Coastal GasLink project costs incurred |
• | $10 million recognized on the termination of the PRGT project in 2017. |
• | higher unrealized gains on risk management activities in 2017. These amounts have been excluded from comparable earnings |
• | recovery of $32 million related to carrying charges on Coastal GasLink project costs incurred, and amounts recognized on the termination of the PRGT project in 2017 |
• | foreign exchange impact on the translation of foreign currency denominated working capital balances |
• | lower realized gains in 2017 compared to 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income |
• | higher interest income along with a $63 million foreign exchange loss in 2017 related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively, resulting in no impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings. |
TransCanada Management's discussion and analysis 2018 | 71 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Income tax expense included in comparable earnings | (693 | ) | (839 | ) | (841 | ) | |||
Specific items: | |||||||||
MLP regulatory liability write-off | 115 | — | — | ||||||
U.S. Tax Reform | 52 | 804 | — | ||||||
Bison asset impairment | 44 | — | — | ||||||
Sales of U.S. Northeast power generation assets | 27 | (177 | ) | (29 | ) | ||||
Tuscarora goodwill impairment | 5 | — | — | ||||||
U.S. Northeast power marketing contracts | 1 | — | — | ||||||
Gain on sale of Cartier Wind power facilities | (27 | ) | — | — | |||||
Bison contract terminations | (8 | ) | — | — | |||||
Energy East impairment charge | — | 302 | — | ||||||
Integration and acquisition related costs – Columbia | — | 22 | 10 | ||||||
Gain on sale of Ontario solar assets | — | 9 | — | ||||||
Keystone XL income tax recoveries | — | 7 | 28 | ||||||
Keystone XL asset costs | — | 6 | 10 | ||||||
Ravenswood goodwill impairment | — | — | 429 | ||||||
Alberta PPA terminations and settlement | — | — | 88 | ||||||
Restructuring costs | — | — | 6 | ||||||
TC Offshore loss on sale | — | — | 1 | ||||||
Risk management activities | 52 | (45 | ) | (54 | ) | ||||
Income tax (expense)/recovery | (432 | ) | 89 | (352 | ) |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Net income attributable to non-controlling interests included in comparable earnings | (315 | ) | (238 | ) | (257 | ) | |||
Specific items: | |||||||||
Bison impairment | 538 | — | — | ||||||
Tuscarora goodwill impairment | 59 | — | — | ||||||
Bison contract terminations | (97 | ) | — | — | |||||
Integration and acquisition related costs – Columbia | — | — | 5 | ||||||
Net loss/(income) attributable to non-controlling interests | 185 | (238 | ) | (252 | ) |
72 | TransCanada Management's discussion and analysis 2018 |
• | a $538 million charge related to the non-controlling interests portion of a $722 million Bison asset impairment charge recorded by TC PipeLines, LP |
• | a $59 million charge related to the non-controlling interests portion of a $79 million Tuscarora goodwill impairment charge recorded by TC PipeLines, LP |
• | $97 million in income related to the non-controlling interests portion of Bison contract termination payments of $130 million received from certain customers and recorded by TC PipeLines, LP. |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Preferred share dividends | (163 | ) | (160 | ) | (109 | ) |
TransCanada Management's discussion and analysis 2018 | 73 |
at December 31 | Per cent of total | Per cent of total | |||||||||||
(millions of $, unless otherwise noted) | 2018 | 2017 | |||||||||||
Notes payable | 2,762 | 3 | 1,763 | 3 | |||||||||
Long-term debt, including current portion | 39,971 | 50 | 34,741 | 50 | |||||||||
Cash and cash equivalents | (446 | ) | (1 | ) | (1,089 | ) | (2 | ) | |||||
Debt | 42,287 | 52 | 35,415 | 51 | |||||||||
Junior subordinated notes | 7,508 | 9 | 7,007 | 10 | |||||||||
Preferred shares | 3,980 | 5 | 3,980 | 6 | |||||||||
Common shareholders' equity1 | 27,013 | 34 | 22,911 | 33 | |||||||||
80,788 | 100 | 69,313 | 100 |
1 | Includes non-controlling interests. |
74 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Net cash provided by operations | 6,555 | 5,230 | 5,069 | ||||||
Net cash used in investing activities | (10,019 | ) | (3,699 | ) | (18,783 | ) | |||
(3,464 | ) | 1,531 | (13,714 | ) | |||||
Net cash provided by/(used in) financing activities | 2,748 | (1,419 | ) | 14,007 | |||||
(716 | ) | 112 | 293 | ||||||
Effect of foreign exchange rate changes on cash and cash equivalents | 73 | (39 | ) | (127 | ) | ||||
(Decrease)/increase in cash and cash equivalents | (643 | ) | 73 | 166 |
• | our ability to generate predictable and growing cash flow from operations |
• | approximately $11.8 billion of unutilized, unsecured credit facilities |
• | our access to capital markets, including through our DRP and Corporate ATM programs, if deemed appropriate. |
year ended December 31 | ||||||||||||
(millions of $) | 2018 | 2017 | 2016 | |||||||||
Net cash provided by operations | 6,555 | 5,230 | 5,069 | |||||||||
Increase/(decrease) in operating working capital | 102 | 273 | (248 | ) | ||||||||
Funds generated from operations | 6,657 | 5,503 | 4,821 | |||||||||
Specific items: | ||||||||||||
Bison contract terminations | (122 | ) | — | — | ||||||||
U.S. Northeast power marketing contracts | 1 | — | — | |||||||||
Integration and acquisition related costs – Columbia | — | 84 | 283 | |||||||||
Keystone XL asset costs | — | 34 | 52 | |||||||||
Net (gain)/loss on sales of U.S. Northeast power generation assets | (14 | ) | 20 | 15 | ||||||||
Comparable funds generated from operations | 6,522 | 5,641 | 5,171 | |||||||||
Dividends on preferred shares | (158 | ) | (155 | ) | (100 | ) | ||||||
Distributions to non-controlling interests | (225 | ) | (283 | ) | (279 | ) | ||||||
Non-recoverable maintenance capital expenditures | (254 | ) | (240 | ) | (310 | ) | ||||||
Comparable distributable cash flow | 5,885 | 4,963 | 4,482 | |||||||||
Comparable distributable cash flow per common share | $6.52 | $5.69 | $5.91 |
TransCanada Management's discussion and analysis 2018 | 75 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Capital spending | |||||||||
Capital expenditures | (9,418 | ) | (7,383 | ) | (5,007 | ) | |||
Capital projects in development | (496 | ) | (146 | ) | (295 | ) | |||
Contributions to equity investments | (1,015 | ) | (1,681 | ) | (765 | ) | |||
(10,929 | ) | (9,210 | ) | (6,067 | ) | ||||
Acquisitions, net of cash acquired | — | — | (13,608 | ) | |||||
Proceeds from sale of assets, net of transaction costs | 614 | 4,683 | 6 | ||||||
Reimbursement of costs related to capital projects in development | 470 | 634 | — | ||||||
Other distributions from equity investments | 121 | 362 | 727 | ||||||
Deferred amounts and other | (295 | ) | (168 | ) | 159 | ||||
Net cash used in investing activities | (10,019 | ) | (3,699 | ) | (18,783 | ) |
• | the 2016 acquisitions of Columbia and Ironwood |
• | higher capital spending in 2017 |
• | proceeds from the sales of our U.S. Northeast power generation assets and solar assets in 2017 |
• | recovery of PRGT project costs. |
76 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Canadian Natural Gas Pipelines | 2,478 | 2,181 | 1,525 | ||||||
U.S. Natural Gas Pipelines | 5,771 | 3,830 | 1,522 | ||||||
Mexico Natural Gas Pipelines | 797 | 1,954 | 1,142 | ||||||
Liquids Pipelines | 581 | 529 | 1,137 | ||||||
Energy | 1,257 | 675 | 708 | ||||||
Corporate | 45 | 41 | 33 | ||||||
10,929 | 9,210 | 6,067 |
1 | Capital spending includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity investments. |
• | sold Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximately US$2.029 billion, before post-closing adjustments |
• | sold TC Hydro for proceeds of approximately US$1.07 billion, before post-closing adjustments |
• | sold our Ontario solar assets for proceeds of approximately $541 million, before post-closing adjustments. |
TransCanada Management's discussion and analysis 2018 | 77 |
year ended December 31 | |||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||
Notes payable issued/(repaid), net | 817 | 1,038 | (329 | ) | |||||
Long-term debt issued, net of issue costs | 6,238 | 3,643 | 12,333 | ||||||
Long-term debt repaid | (3,550 | ) | (7,085 | ) | (7,153 | ) | |||
Junior subordinated notes issued, net of issue costs | — | 3,468 | 1,549 | ||||||
Dividends and distributions paid | (1,954 | ) | (1,777 | ) | (1,815 | ) | |||
Common shares issued, net of issue costs | 1,148 | 274 | 7,747 | ||||||
Common shares repurchased | — | — | (14 | ) | |||||
Preferred shares issued, net of issue costs | — | — | 1,474 | ||||||
Partnership units of TC PipeLines, LP issued, net of issue costs | 49 | 225 | 215 | ||||||
Common units of Columbia Pipelines Partners LP acquired | — | (1,205 | ) | — | |||||
Net cash provided by/(used in) financing activities | 2,748 | (1,419 | ) | 14,007 |
(millions of Canadian $, unless otherwise noted) | ||||||||||||
Company | Issue date | Type | Maturity Date | Amount | Interest rate | |||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||||
October 2018 | Senior Unsecured Notes | March 2049 | US 1,000 | 5.10 | % | |||||||
October 2018 | Senior Unsecured Notes | May 2028 | US 400 | 4.25 | % | |||||||
July 2018 | Medium Term Notes | July 2048 | 800 | 4.18 | % | |||||||
July 2018 | Medium Term Notes | March 2028 | 200 | 3.39 | % | |||||||
May 2018 | Senior Unsecured Notes | May 2048 | US 1,000 | 4.875 | % | |||||||
May 2018 | Senior Unsecured Notes | May 2038 | US 500 | 4.75 | % | |||||||
May 2018 | Senior Unsecured Notes | May 2028 | US 1,000 | 4.25 | % | |||||||
NORTH BAJA PIPELINE, LLC | ||||||||||||
December 2018 | Unsecured Term Loan | December 2021 | US 50 | Floating |
78 | TransCanada Management's discussion and analysis 2018 |
(millions of Canadian $, unless otherwise noted) | ||||||||||
Company | Retirement date | Type | Amount | Interest rate | ||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||
January 2019 | Senior Unsecured Notes | US 750 | 7.125 | % | ||||||
January 2019 | Senior Unsecured Notes | US 400 | 3.125 | % | ||||||
August 2018 | Senior Unsecured Notes | US 850 | 6.50 | % | ||||||
March 2018 | Debentures | 150 | 9.45 | % | ||||||
January 2018 | Senior Unsecured Notes | US 500 | 1.875 | % | ||||||
January 2018 | Senior Unsecured Notes | US 250 | Floating | |||||||
TC PIPELINES, LP | ||||||||||
December 2018 | Unsecured Term Loan | US 170 | Floating | |||||||
COLUMBIA PIPELINE GROUP, INC. | ||||||||||
June 2018 | Senior Unsecured Notes | US 500 | 2.45 | % |
TransCanada Management's discussion and analysis 2018 | 79 |
as at February 11, 2019 | ||
Common Shares | issued and outstanding | |
922 million | ||
Preferred Shares | issued and outstanding | convertible to |
Series 1 | 9.5 million | Series 2 preferred shares |
Series 2 | 12.5 million | Series 1 preferred shares |
Series 3 | 8.5 million | Series 4 preferred shares |
Series 4 | 5.5 million | Series 3 preferred shares |
Series 5 | 12.7 million | Series 6 preferred shares |
Series 6 | 1.3 million | Series 5 preferred shares |
Series 7 | 24 million | Series 8 preferred shares |
Series 9 | 18 million | Series 10 preferred shares |
Series 11 | 10 million | Series 12 preferred shares |
Series 13 | 20 million | Series 14 preferred shares |
Series 15 | 40 million | Series 16 preferred shares |
Options to buy common shares | outstanding | exercisable |
12 million | 8 million |
80 | TransCanada Management's discussion and analysis 2018 |
year ended December 31 | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
Dividends declared | ||||||||||||
per common share | $2.76 | $2.50 | $2.26 | |||||||||
per Series 1 preferred share | $0.8165 | $0.8165 | $0.8165 | |||||||||
per Series 2 preferred share | $0.78835 | $0.62138 | $0.60648 | |||||||||
per Series 3 preferred share | $0.538 | $0.538 | $0.538 | |||||||||
per Series 4 preferred share | $0.62748 | $0.46138 | $0.44648 | |||||||||
per Series 5 preferred share | $0.56575 | $0.56575 | $0.56575 | |||||||||
per Series 6 preferred share | $0.69341 | $0.55275 | $0.50648 | |||||||||
per Series 7 preferred share | $1.00 | $1.00 | $1.00 | |||||||||
per Series 9 preferred share | $1.0625 | $1.0625 | $1.0625 | |||||||||
per Series 11 preferred share | $0.95 | $0.95 | $1.1875 | |||||||||
per Series 13 preferred share | $1.375 | $1.375 | $1.18525 | |||||||||
per Series 15 preferred share | $1.225 | $1.225 | $0.3323 |
Amount | Unused capacity | Borrower | Description | Matures | ||||
Committed, syndicated, revolving, extendible, senior unsecured credit facilities: | ||||||||
$3.0 billion | $3.0 billion | TCPL | Supports TCPL's Canadian dollar commercial paper program and is used for general corporate purposes | December 2023 | ||||
US$4.5 billion | US$4.5 billion | TCPL/TCPL USA/Columbia/TAIL | Supports TCPL and TCPL USA's U.S. dollar commercial paper programs, and is used for general corporate purposes of the borrowers, guaranteed by TCPL | December 2019 | ||||
US$1.0 billion | US$1.0 billion | TCPL/TCPL USA/Columbia/TAIL | Used for general corporate purposes of the borrowers, guaranteed by TCPL | December 2021 | ||||
Demand senior unsecured revolving credit facilities: | ||||||||
$2.1 billion | $1.0 billion | TCPL/TCPL USA | Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL | Demand | ||||
MXN$5.0 billion | MXN$5.0 billion | Mexican subsidiary | Used for Mexico general corporate purposes, guaranteed by TCPL | Demand |
TransCanada Management's discussion and analysis 2018 | 81 |
at December 31, 2018 | Total | < 1 year | 1 - 3 years | 4 - 5 years | > 5 years | |||||||||
(millions of $) | ||||||||||||||
Notes payable | 2,762 | 2,762 | — | — | — | |||||||||
Long-term debt and junior subordinated notes | 47,479 | 3,465 | 4,932 | 4,031 | 35,051 | |||||||||
Operating leases1 | 729 | 74 | 143 | 130 | 382 | |||||||||
Purchase obligations | 8,187 | 2,985 | 3,640 | 372 | 1,190 | |||||||||
59,157 | 9,286 | 8,715 | 4,533 | 36,623 |
at December 31, 2018 | Total | < 1 year | 1 - 3 years | 4 - 5 years | > 5 years | |||||||||
(millions of $) | ||||||||||||||
Long-term debt | 27,447 | 1,941 | 3,593 | 3,163 | 18,750 | |||||||||
Junior subordinated notes | 28,039 | 416 | 833 | 834 | 25,956 | |||||||||
55,486 | 2,357 | 4,426 | 3,997 | 44,706 |
82 | TransCanada Management's discussion and analysis 2018 |
at December 31, 2018 | Total | < 1 year | 1 - 3 years | 4 - 5 years | > 5 years | |||||||||
(millions of $) | ||||||||||||||
Canadian Natural Gas Pipelines | ||||||||||||||
Transportation by others1 | 859 | 83 | 161 | 138 | 477 | |||||||||
Capital spending2 | 4,647 | 1,700 | 2,947 | — | — | |||||||||
U.S. Natural Gas Pipelines | ||||||||||||||
Transportation by others1 | 700 | 119 | 199 | 108 | 274 | |||||||||
Capital spending2 | 50 | 50 | — | — | — | |||||||||
Mexico Natural Gas Pipelines | ||||||||||||||
Capital spending2 | 342 | 287 | 55 | — | — | |||||||||
Liquids Pipelines | ||||||||||||||
Capital spending2 | 406 | 406 | — | — | — | |||||||||
Other | 22 | 5 | 7 | 6 | 4 | |||||||||
Energy | ||||||||||||||
Commodity purchases | 91 | 63 | 28 | — | — | |||||||||
Capital spending2 | 700 | 199 | 163 | 56 | 282 | |||||||||
Other3 | 300 | 34 | 56 | 58 | 152 | |||||||||
Corporate | ||||||||||||||
Capital spending2 | 70 | 39 | 24 | 6 | 1 | |||||||||
8,187 | 2,985 | 3,640 | 372 | 1,190 |
1 | Demand rates are subject to change. The contractual obligations in the table are based on demand volumes only and exclude variable charges incurred when volumes flow. |
2 | Amounts are primarily for capital expenditures and contributions to equity investments for capital projects. Amounts are estimates and are subject to variability based on timing of construction and project requirements. |
3 | Includes estimates of certain amounts which are subject to change depending on plant-fired hours, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for fuel transportation. |
• | senior debt |
• | hybrid securities |
• | preferred shares |
• | asset sales |
• | project financing |
• | potential involvement of strategic or financial partners. |
• | common shares issued under our DRP |
• | common shares issued under our Corporate ATM program |
• | discrete common equity issuances. |
TransCanada Management's discussion and analysis 2018 | 83 |
• | interest rates |
• | actual returns on plan assets |
• | changes to actuarial assumptions and plan design |
• | actual plan experience versus projections |
• | amendments to pension plan regulations and legislation. |
84 | TransCanada Management's discussion and analysis 2018 |
• | the Human Resources Committee oversees executive resourcing, organizational capabilities and compensation risk to ensure compensation practices align with our overall business strategy |
• | the HSSE Committee oversees operational, health, safety, sustainability and environmental risk |
• | the Audit Committee oversees management's role in managing financial risk. |
Risk and Description | Impact | Monitoring and Mitigation |
Business interruption | ||
Operational risks, including equipment malfunctions and breakdowns, labour disputes, or natural disasters and other catastrophic events, including those related to climate change, acts of terror and sabotage. | Decrease in revenues and increase in operating costs, legal proceedings or regulatory actions or other expenses all of which could reduce our earnings. Losses not recoverable through tolls or contracts or covered by insurance could have an adverse effect on operations, cash flow and financial position. Certain events could lead to risk of injury and environmental damage. | We have TOMS that includes our corporate health, safety, sustainability, environment and asset integrity programs to prevent incidents and protect people, the environment and our assets. TOMS includes incident, emergency and crisis management programs to ensure TransCanada can effectively respond to operational risk events, minimize loss or injury and enhance our ability to resume operations. This is supported by our business continuity program that identifies critical business processes and develops corresponding business resumption plans. We also have a comprehensive insurance program to mitigate a certain portion of these risks, but insurance does not cover all events in all circumstances. |
Cyber security | ||
We rely on our information technology to process, transmit and store electronic information, including information we use to safely operate our assets. We continue to face cyber security risks, and could be subject to cyber-security events directed against our information technology. The methods used to obtain unauthorized access, disable or degrade service or sabotage systems are constantly evolving and may be difficult to anticipate or to detect for long periods of time. | A breach in the security of our information technology could expose our business to a risk of loss, misuse or interruption of critical information and functions. This could affect our operations, damage our assets, result in safety incidents, damage to the environment, and/or result in reputational harm, competitive disadvantage, regulatory enforcement actions and potential litigation, which could have a material adverse effect on our operations, financial position and results of operations. | We have a comprehensive cyber security strategy which aligns with industry and recognized standards for cyber security. This strategy is regularly reviewed and updated, and the status of our cyber security program is reported to the Audit Committee on a quarterly basis. The program includes cyber security risk assessments, continuous monitoring of networks and other information sources for threats to the organization, comprehensive incident response plans/processes and a cyber security awareness program for employees. We have insurance which may cover losses from physical damage to our facilities as a result of a cyber security event, but insurance does not cover all events in all circumstances. |
TransCanada Management's discussion and analysis 2018 | 85 |
Risk and Description | Impact | Monitoring and Mitigation |
Reputation and relationships | ||
Our operations and growth prospects require us to have strong relationships with key stakeholders including Indigenous communities, landowners, governments and government agencies, and environmental non-governmental organizations. Inadequately managing expectations and issues important to stakeholders, including those related to climate change, could affect our reputation and our ability to operate and grow, as well as our access to and cost of capital. | Our reputation with stakeholders, including Indigenous communities, can have a significant impact on our operations and projects, infrastructure development and overall reputation. Should investors develop negative perceptions regarding our energy infrastructure business, future access to investment capital could be negatively impacted. | Our four core values – safety, integrity, responsibility and collaboration – are at the heart of our commitment to stakeholder engagement, and guide us in our interactions with stakeholders. We also have specific stakeholder programs and policies that set requirements, assess risks and facilitate compliance with legal and policy requirements. |
Access to capital at a competitive cost | ||
We require substantial amounts of capital in the form of debt and equity to finance our portfolio of growth projects and maturing debt obligations at costs that are sufficiently lower than the returns on our investments. | Significant deterioration in market conditions for an extended period of time and changes in investor sentiment could affect our ability to access capital at a competitive cost, which could negatively impact our ability to deliver an attractive return on our investments. | We operate within our financial means and risk tolerances, maintain a diverse array of funding levers and also utilize portfolio management as an important component of our financing program. In addition, we have candid and proactive engagement with the investment community, including credit rating agencies, with the objective of keeping them apprised of developments in our business and factually communicating our prospects, risks and challenges. |
Capital allocation strategy | ||
To be competitive, we must offer energy infrastructure services in supply and demand areas, and for forms of energy that are attractive to customers. | Should alternative lower-carbon forms of energy result in decreased demand for our current services, the value of our long-lived energy infrastructure assets could be negatively impacted. | We have a diverse portfolio of assets and we utilize portfolio management to divest of non-strategic assets. We conduct analyses to identify resilient supply basins as part of our energy fundamentals and strategic development reviews. We also monitor the development of innovative technologies to inform our capital allocation strategy. |
Execution and capital costs | ||
Investing in large infrastructure projects involves substantial capital commitments and associated execution risks based on the assumption that these assets will deliver an attractive return on investment in the future. | While we carefully determine the expected cost of our capital projects, under some commercial arrangements we bear capital cost overrun and schedule risk which may decrease our return on these projects. | Our Project Governance Program supports project execution and operational excellence. The program aligns with TOMS which provides the framework and standards to optimize project execution, ensuring timely and on budget execution. We prefer to contractually structure our projects to recover development costs if a project does not proceed along with mechanisms to minimize the impact should cost overruns occur. However, under some commercial arrangements, we share or bear the cost of execution risk. |
• | planning – risk and regulatory assessment, objective and target setting, defining roles and responsibilities |
• | implementing – development and implementation of programs, procedures and standards to manage operational risk |
• | reporting – incident reporting and investigation, and performance monitoring |
• | action – assurance activities and review of performance by management. |
86 | TransCanada Management's discussion and analysis 2018 |
• | overall HSSE corporate governance |
• | operational performance and preventive maintenance metrics |
• | asset integrity programs |
• | emergency preparedness, incident response and evaluation |
• | people and process safety performance metrics |
• | our Environment Program |
• | developments in and compliance with applicable legislation and regulations, including those related to the environment |
• | prevention, mitigation and management of risks related to HSSE matters, including climate change related risks which may adversely impact TransCanada |
• | sustainability matters, including social, environmental and climate-change related matters |
• | management's approach to voluntary public disclosure on HSSE matters. |
• | changing regulations and costs associated with our emissions of air pollutants and GHG |
• | product releases, including crude oil, diluent and natural gas, that may cause harm to the environment (land, water and air) |
• | use, storage and disposal of chemicals and hazardous materials |
• | conformance and compliance with corporate and regulatory policies and requirements as well as new regulations. |
TransCanada Management's discussion and analysis 2018 | 87 |
• | environmental laws and regulations and their interpretations and enforcement change |
• | new claims can be brought against our existing or discontinued assets |
• | our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigations or agreements |
• | new contaminated sites may be found, or what we know about existing sites could change |
• | where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty. |
88 | TransCanada Management's discussion and analysis 2018 |
• | Environment and Climate Change Canada (ECCC) issued the final Methane Reduction Regulation on April 26, 2018. The regulations detail requirements to reduce methane emissions through operational and capital modifications. There are multiple timeframes for compliance depending on the provision, beginning in 2020. Alberta, British Columbia and Saskatchewan have drafted their own methane regulations which take the place of the federal regulation in those jurisdictions. However, for the federally regulated facilities in these jurisdictions, the federal methane regulation will be applicable. For most of TransCanada’s Canadian pipeline assets, it is likely that the federal regulation will be applicable. Compliance will involve equipment retrofits, frequent leak detection and repair surveys and measurements to quantify emission reductions and associated annual reporting. Power facilities are not affected by this regulation |
• | B.C. has a tax on GHG emissions from fossil fuel combustion. We recover the compliance costs through the tolls our customers pay |
• | in Alberta, the CCIR replaced the SGER effective January 1, 2018. This regulation requires established industrial facilities with GHG emissions above a certain threshold to reduce their emissions below an intensity baseline. The CCIR covers our natural gas pipelines and Energy assets in Alberta. Canadian natural gas pipeline compliance costs are recovered through regulated tolls. A portion of the compliance costs for the Energy assets are recovered through market pricing and hedging activities |
• | Québec has a GHG cap-and-trade program under the Western Climate Initiative (WCI) GHG emissions market. In Québec, the Bécancour cogeneration plant is subject to this program. The government allocates free emission units for the majority of Bécancour's compliance requirements. The remaining requirements were met with GHG instruments purchased at auctions or secondary markets. The costs of these emissions units are recovered through commercial contracts. The Canadian Mainline natural gas pipeline facilities in Québec are also subject to this program and compliance instruments have been purchased in order to comply with the requirements of this initiative |
• | Ontario repealed its cap-and-trade program in 2018. The compliance credits purchased under the previous cap-and-trade program have been retired by the new government. With the repeal of the cap-and-trade program, Ontario does not have carbon pricing regulation, therefore, TransCanada’s electricity and pipeline facilities in this jurisdiction are subject to the Canadian Federal OBPS as of January 1, 2019. Federal OBPS applies to electric generation facilities with annual emissions greater than 50,000 tonnes of CO2 equivalent. At this time we do not anticipate any material impact to the financial performance of our Ontario natural gas facilities as a result of this program. |
• | the U.S. Environmental Protection Agency (EPA) published regulations related to fugitive methane emissions for new and modified compressor stations in the natural gas transmission and storage sector in 2015. In 2017, the EPA indicated its intention to reconsider this regulation. In 2018, with direction from the Trump administration, the EPA is working on reducing the requirements of this regulation |
• | on March 23, 2017, the California Air Resources Board published regulations related to monitoring and repairing methane leaks. Tuscarora Gas Transmission facilities are required to comply with these regulations |
• | Washington State adopted emission standards to cap and reduce GHGs from certain stationary sources in September 2016. Some GTN compressor stations in Washington are potentially impacted by the standards beginning in 2020 |
• | the Pennsylvania Department of Environmental Protection has adopted new operating permits for oil and gas facilities that include numerous requirements including methane leak detection and repair |
• | California has a GHG cap-and-trade program under the WCI GHG emissions market. In California, TransCanada has costs associated with the cap-and-trade program with respect to our electricity marketing activities. |
TransCanada Management's discussion and analysis 2018 | 89 |
• | on November 6, 2018, the Government of Mexico published a new regulation that established guidelines for the prevention and control of methane emissions in the hydrocarbon sector, which will impact our Mexico natural gas pipelines. Companies will have one year to comply with the regulations which include equipment requirements such as installation of vapor recovery systems and detection and repair of leaks, as well as administrative requirements including the identification of methane emissions and implementation of a program for emissions reporting. |
• | the Government of Canada has finalized a Federal plan to have carbon pricing in place in all Canadian jurisdictions. ECCC is in the process of finalizing the Federal OBPS regulation to impose carbon pricing for larger industrial facilities and will set federal benchmarks for GHG emissions for various industry sectors. This new federal regulation will apply to the provinces of Ontario, Manitoba, Saskatchewan, and New Brunswick as those jurisdictions do not currently have a provincial plan in place for carbon pricing or meet the criteria of the Federal plan. This may result in increased costs for current pipeline and energy facilities in those jurisdictions |
• | the Government of Canada has proposed a Federal plan, the Clean Fuel Standard (CFS), to implement a single national standard encompassing all fuel types and applications. As part of the CFS, compressor station electrification is proposed by the Federal Government as a mechanism to reduce natural gas transmission GHG emissions. This could have negative impacts to our Canadian natural gas compression assets. Efforts to influence this policy are being managed through CEPA and CGA. Different components of the CFS regulations are expected to be released through 2019 |
• | the Government of Saskatchewan has announced that certain large industrial emitters will be subject to a provincially proposed carbon pricing system based on an OBPS approach, which has potential to impact our Canadian natural gas pipelines in that province. This proposed system only partially meets the Federal plan and, therefore, the Federal OBPS will apply to emission sources not covered by the proposed system, including electricity generation and natural gas pipelines |
• | New York State announced its intent to adopt regulations to reduce methane from existing, new and modified facilities. New York has not yet proposed regulations, but the Governor announced the State’s plan to achieve its clean energy goals by 2030, which includes a 40% reduction from 1990 emissions levels. Impacts to our facilities are dependent on the specifics of the regulations once they are proposed, but it is likely that our compression facilities in New York State would be affected |
• | Maryland announced its intent to establish fugitive methane regulations for compressor stations. Maryland has been working with operators, including TransCanada, to develop regulations to reduce greenhouse gases. TransCanada has only one compressor station in Maryland, and it is electric, therefore, no significant impact is expected. |
90 | TransCanada Management's discussion and analysis 2018 |
• | forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future |
• | swaps – agreements between two parties to exchange streams of payments over time according to specified terms |
• | options – agreements that convey the right, but not the obligation of the purchaser, to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. |
• | in our power generation business, we manage our exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets |
• | in our non-regulated natural gas storage business, our exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins |
• | in our liquids marketing business, we enter into pipeline and storage terminal capacity contracts. We fix a portion of our exposure on these contracts by entering into derivative instruments to manage our variable price fluctuations that arise from physical liquids transactions. |
TransCanada Management's discussion and analysis 2018 | 91 |
2018 | 1.30 | ||
2017 | 1.30 | ||
2016 | 1.33 |
year ended December 31 | ||||||||||
(millions of US$) | 2018 | 2017 | 2016 | |||||||
U.S. Natural Gas Pipelines comparable EBIT | 1,830 | 1,360 | 947 | |||||||
Mexico Natural Gas Pipelines comparable EBIT1 | 486 | 353 | 215 | |||||||
U.S. Liquids Pipelines comparable EBIT | 876 | 604 | 482 | |||||||
U.S. Power comparable EBIT2 | — | 100 | 285 | |||||||
Interest on U.S. dollar-denominated long-term debt and junior subordinated notes | (1,325 | ) | (1,269 | ) | (1,127 | ) | ||||
Capitalized interest on U.S. dollar-denominated capital expenditures | 15 | 3 | 22 | |||||||
U.S. dollar-denominated allowance for funds used during construction | 326 | 259 | 181 | |||||||
U.S. comparable non-controlling interests and other | (264 | ) | (195 | ) | (195 | ) | ||||
1,944 | 1,215 | — | 810 |
1 | Excludes interest expense on our inter-affiliate loan with Sur de Texas which is offset in Interest income and other. |
2 | Effective January 1, 2018, U.S. Power is no longer included in comparable EBIT. |
• | cash and cash equivalents |
• | accounts receivable |
• | available-for-sale assets |
• | the fair value of derivative assets |
• | a loan receivable. |
92 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 93 |
• | a $722 million pre-tax impairment of the carrying value of our investment in Bison ($140 million after-tax and net of non-controlling interests) |
• | a $79 million pre-tax impairment of the carrying value of Tuscarora's goodwill ($15 million after-tax and net of non-controlling interests). |
• | a $954 million after-tax charge on the carrying value of our investment in Energy East and related projects |
• | a $16 million after-tax charge on the remaining carrying value of certain Energy turbine equipment |
• | a $12 million after-tax charge related to the remaining carrying value of our investment in TransGas. |
94 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 95 |
at December 31 | ||||||
(millions of $) | 2018 | 2017 | ||||
Other current assets | 737 | 332 | ||||
Intangible and other assets | 61 | 73 | ||||
Accounts payable and other | (922 | ) | (387 | ) | ||
Other long-term liabilities | (42 | ) | (72 | ) | ||
(166 | ) | (54 | ) |
96 | TransCanada Management's discussion and analysis 2018 |
at December 31, 2018 | Total fair value | < 1 year | 1 - 3 years | 4 - 5 years | > 5 years | ||||||||||
(millions of $) | |||||||||||||||
Derivative instruments held for trading | |||||||||||||||
Assets | 767 | 717 | 50 | — | — | ||||||||||
Liabilities | (838 | ) | (810 | ) | (23 | ) | — | (5 | ) | ||||||
Derivative instruments in hedging relationships | |||||||||||||||
Assets | 31 | 20 | 8 | 2 | 1 | ||||||||||
Liabilities | (126 | ) | (112 | ) | (4 | ) | (2 | ) | (8 | ) | |||||
(166 | ) | (185 | ) | 31 | — | (12 | ) |
year ended December 31 | ||||||||
(millions of $) | 2018 | 2017 | 2016 | |||||
Derivative instruments held for trading1 | ||||||||
Amount of unrealized gains/(losses) in the year | ||||||||
Commodities2 | 28 | 62 | 123 | |||||
Foreign exchange | (248 | ) | 88 | 25 | ||||
Interest rate | — | (1 | ) | — | ||||
Amount of realized gains/(losses) in the year | ||||||||
Commodities | 351 | (107 | ) | (204 | ) | |||
Foreign exchange | (24 | ) | 18 | 62 | ||||
Interest rate | — | 1 | — | |||||
Derivative instruments in hedging relationships | ||||||||
Amount of realized (losses)/gains in the year | ||||||||
Commodities | (1 | ) | 23 | (167 | ) | |||
Foreign exchange | — | 5 | (101 | ) | ||||
Interest rate | (1 | ) | 1 | 4 |
1 | Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in interest expense and interest income and other, respectively. |
2 | In 2018 and 2017, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2016 – net loss of $42 million). |
TransCanada Management's discussion and analysis 2018 | 97 |
year ended December 31 | Revenues (Energy) | Interest Expense | ||||||||||||||||
(millions of $) | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | ||||||||||||
Total Amount Presented in the Condensed Consolidated Statement of Income | 2,124 | 3,593 | 4,206 | (2,265 | ) | (2,069 | ) | (1,998 | ) | |||||||||
Fair Value Hedges | ||||||||||||||||||
Interest rate contracts | ||||||||||||||||||
Hedged items | — | — | — | (71 | ) | (74 | ) | (74 | ) | |||||||||
Derivatives designated as hedging instruments | — | — | — | (4 | ) | 1 | 8 | |||||||||||
Cash Flow Hedges | ||||||||||||||||||
Reclassification of gains/(losses) on derivative | ||||||||||||||||||
instruments from AOCI to net income1 | ||||||||||||||||||
Interest rate contracts | — | — | — | 22 | 17 | 14 | ||||||||||||
Commodity contracts | 5 | (20 | ) | 57 | — | — | — |
1 | There are no amounts recognized in earnings that were excluded from effectiveness testing. Refer to the notes to our Consolidated financial statements. |
98 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 99 |
100 | TransCanada Management's discussion and analysis 2018 |
TransCanada Management's discussion and analysis 2018 | 101 |
year ended December 31 | ||||||||
(millions of $, except per share amounts) | 2018 | 2017 | 2016 | |||||
Comparable EBITDA | ||||||||
Canadian Natural Gas Pipelines | 2,379 | 2,144 | 2,182 | |||||
U.S. Natural Gas Pipelines | 3,035 | 2,357 | 1,682 | |||||
Mexico Natural Gas Pipelines | 607 | 519 | 332 | |||||
Liquids Pipelines | 1,849 | 1,348 | 1,152 | |||||
Energy | 752 | 1,030 | 1,281 | |||||
Corporate | (59 | ) | (21 | ) | 18 | |||
Comparable EBITDA | 8,563 | 7,377 | 6,647 | |||||
Depreciation and amortization | (2,350 | ) | (2,048 | ) | (1,939 | ) | ||
Comparable EBIT | 6,213 | 5,329 | 4,708 | |||||
Specific items: | ||||||||
Bison asset impairment | (722 | ) | — | — | ||||
Tuscarora goodwill impairment | (79 | ) | — | — | ||||
U.S. Northeast power marketing contracts | (5 | ) | — | — | ||||
Gain on sale of Cartier Wind power facilities | 170 | — | — | |||||
Bison contract terminations | 130 | — | — | |||||
Foreign exchange gain – inter-affiliate loan | 5 | 63 | — | |||||
Energy East impairment charge | — | (1,256 | ) | — | ||||
Integration and acquisition related costs – Columbia | — | (91 | ) | (179 | ) | |||
Keystone XL asset costs | — | (34 | ) | (52 | ) | |||
Net gain/(loss) on sales of U.S. Northeast power generation assets | — | 484 | (844 | ) | ||||
Gain on sale of Ontario solar assets | — | 127 | — | |||||
Ravenswood goodwill impairment | — | — | (1,085 | ) | ||||
Alberta PPA terminations and settlement | — | — | (332 | ) | ||||
Restructuring costs | — | — | (22 | ) | ||||
TC Offshore loss on sale | — | — | (4 | ) | ||||
Risk management activities1 | 52 | 62 | 123 | |||||
Segmented earnings | 5,764 | 4,684 | 2,313 |
1 | year ended December 31 | ||||||||||
(millions of $) | 2018 | 2017 | 2016 | ||||||||
Canadian Power | 3 | 11 | 4 | ||||||||
U.S. Power | (11 | ) | 39 | 113 | |||||||
Liquids marketing | 71 | — | (2 | ) | |||||||
Natural Gas Storage | (11 | ) | 12 | 8 | |||||||
Total unrealized gains from risk management activities | 52 | 62 | 123 |
102 | TransCanada Management's discussion and analysis 2018 |
2018 | Fourth | Third | Second | First | ||||||||||||
Revenues | 3,904 | 3,156 | 3,195 | 3,424 | ||||||||||||
Net income attributable to common shares | 1,092 | 928 | 785 | 734 | ||||||||||||
Comparable earnings | 946 | 902 | 768 | 864 | ||||||||||||
Share statistics: | ||||||||||||||||
Net income per common share – basic and diluted | $1.19 | $1.02 | $0.88 | $0.83 | ||||||||||||
Comparable earnings per common share | $1.03 | $1.00 | $0.86 | $0.98 | ||||||||||||
Dividends declared per common share | $0.69 | $0.69 | $0.69 | $0.69 |
2017 | Fourth | Third | Second | First | ||||||||||||
Revenues | 3,617 | 3,195 | 3,230 | 3,407 | ||||||||||||
Net income attributable to common shares | 861 | 612 | 881 | 643 | ||||||||||||
Comparable earnings | 719 | 614 | 659 | 698 | ||||||||||||
Share statistics: | ||||||||||||||||
Net income per common share – basic and diluted | $0.98 | $0.70 | $1.01 | $0.74 | ||||||||||||
Comparable earnings per common share | $0.82 | $0.70 | $0.76 | $0.81 | ||||||||||||
Dividends declared per common share | $0.625 | $0.625 | $0.625 | $0.625 |
• | regulators' decisions |
• | negotiated settlements with shippers |
• | acquisitions and divestitures |
• | developments outside of the normal course of operations |
• | newly constructed assets being placed in service. |
• | regulatory decisions |
• | developments outside of the normal course of operations |
• | newly constructed assets being placed in service |
• | demand for uncontracted transportation services |
• | liquids marketing activities |
• | certain fair value adjustments. |
• | weather |
• | customer demand |
• | market prices for natural gas and power |
• | planned and unplanned plant outages |
• | acquisitions and divestitures |
• | certain fair value adjustments |
• | developments outside of the normal course of operations |
• | newly constructed assets being placed in service. |
TransCanada Management's discussion and analysis 2018 | 103 |
• | a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities |
• | a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions |
• | a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform |
• | a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets |
• | $25 million of after-tax income recognized on the Bison contract terminations |
• | a $140 million after-tax impairment charge on Bison |
• | a $15 million after-tax goodwill impairment charge on Tuscarora |
• | an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts. |
• | after-tax income of $8 million related to our U.S. Northeast power marketing contracts. |
• | an after-tax loss of $11 million related to our U.S. Northeast power marketing contracts. |
• | an after-tax gain of $6 million related to our U.S. Northeast power marketing contracts, primarily due to income recognized on the sale of our retail contracts. |
• | an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform |
• | a $136 million after-tax gain related to the sale of our Ontario solar assets |
• | a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets |
• | a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications |
• | a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets. |
• | an incremental net loss of $12 million after tax related to the monetization of our U.S. Northeast power generation assets |
• | an after-tax charge of $30 million for integration-related costs associated with the acquisition of Columbia |
• | an after-tax charge of $8 million related to the maintenance of Keystone XL assets. |
• | a $265 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets which included a $441 million after-tax gain on the sale of TC Hydro and a loss of $176 million after tax on the sale of the thermal and wind package |
• | an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia |
• | an after-tax charge of $4 million related to the maintenance of Keystone XL assets. |
• | a charge of $24 million after tax for integration-related costs associated with the acquisition of Columbia |
• | a charge of $10 million after tax for costs related to the monetization of our U.S. Northeast power generation assets |
• | a charge of $7 million after tax related to the maintenance of Keystone XL assets |
• | a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. |
104 | TransCanada Management's discussion and analysis 2018 |
three months ended December 31 | 2018 | 2017 | ||||||
(millions of $, except per share amounts) | ||||||||
Canadian Natural Gas Pipelines | 450 | 333 | ||||||
U.S. Natural Gas Pipelines | (34 | ) | 461 | |||||
Mexico Natural Gas Pipelines | 128 | 93 | ||||||
Liquids Pipelines | 532 | (932 | ) | |||||
Energy | 315 | 472 | ||||||
Corporate | 23 | 63 | ||||||
Total segmented earnings | 1,414 | 490 | ||||||
Interest expense | (603 | ) | (541 | ) | ||||
Allowance for funds used during construction | 161 | 140 | ||||||
Interest income and other | (215 | ) | (9 | ) | ||||
Income before income taxes | 757 | 80 | ||||||
Income tax (expense)/recovery | (38 | ) | 870 | |||||
Net income | 719 | 950 | ||||||
Net loss/(income) attributable to non-controlling interests | 414 | (49 | ) | |||||
Net income attributable to controlling interests | 1,133 | 901 | ||||||
Preferred share dividends | 41 | 40 | ||||||
Net income attributable to common shares | 1,092 | 861 | ||||||
Net income per common share – basic and diluted | $1.19 | $0.98 |
• | a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities |
• | a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions |
• | a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform |
• | a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets |
• | $25 million of after-tax income recognized on the Bison contract terminations |
• | a $140 million after-tax impairment charge on Bison |
• | a $15 million after-tax goodwill impairment charge on Tuscarora |
• | an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts. |
• | an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform |
• | a $136 million after-tax gain related to the sale of our Ontario solar assets |
• | a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets |
• | a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications |
• | a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets. |
TransCanada Management's discussion and analysis 2018 | 105 |
three months ended December 31 | 2018 | 2017 | ||||||
(millions of $, except per share amounts) | ||||||||
Net income attributable to common shares | 1,092 | 861 | ||||||
Specific items (net of tax): | ||||||||
Gain on sale of Cartier Wind power facilities | (143 | ) | — | |||||
MLP regulatory liability write-off | (115 | ) | — | |||||
U.S. Tax Reform | (52 | ) | (804 | ) | ||||
Net gain on sales of U.S. Northeast power generation assets | (27 | ) | (64 | ) | ||||
Bison contract terminations | (25 | ) | — | |||||
Bison asset impairment | 140 | — | ||||||
Tuscarora goodwill impairment | 15 | — | ||||||
U.S. Northeast power marketing contracts | 7 | — | ||||||
Gain on sale of Ontario solar assets | — | (136 | ) | |||||
Energy East impairment charge | — | 954 | ||||||
Keystone XL asset costs | — | 9 | ||||||
Risk management activities1 | 54 | (101 | ) | |||||
Comparable earnings | 946 | 719 | ||||||
Net income per common share | $1.19 | $0.98 | ||||||
Specific items (net of tax): | ||||||||
Gain on sale of Cartier Wind power facilities | (0.16 | ) | — | |||||
MLP regulatory liability write-off | (0.13 | ) | — | |||||
U.S. Tax Reform | (0.06 | ) | (0.92 | ) | ||||
Net gain on sales of U.S. Northeast power generation assets | (0.03 | ) | (0.08 | ) | ||||
Bison contract terminations | (0.03 | ) | — | |||||
Bison asset impairment | 0.16 | — | ||||||
Tuscarora goodwill impairment | 0.02 | — | ||||||
U.S. Northeast power marketing contracts | 0.01 | — | ||||||
Gain on sale of Ontario solar assets | — | (0.16 | ) | |||||
Energy East impairment charge | — | 1.09 | ||||||
Keystone XL asset costs | — | 0.01 | ||||||
Risk management activities1 | 0.06 | (0.10 | ) | |||||
Comparable earnings per common share | $1.03 | $0.82 |
1 | three months ended December 31 | 2018 | 2017 | |||||
(millions of $) | ||||||||
Liquids marketing | 81 | 15 | ||||||
Canadian Power | — | 6 | ||||||
U.S. Power | 20 | 136 | ||||||
Natural Gas Storage | (5 | ) | 7 | |||||
Foreign exchange | (169 | ) | (1 | ) | ||||
Income tax attributable to risk management activities | 19 | (62 | ) | |||||
Total unrealized (losses)/gains from risk management activities | (54 | ) | 101 |
106 | TransCanada Management's discussion and analysis 2018 |
three months ended December 31 | ||||||
(millions of $) | 2018 | 2017 | ||||
Comparable EBITDA | 2,453 | 1,903 | ||||
Adjustments: | ||||||
Depreciation and amortization | (681 | ) | (516 | ) | ||
Interest expense included in comparable earnings | (603 | ) | (541 | ) | ||
Allowance for funds used during construction | 161 | 140 | ||||
Interest income and other included in comparable earnings | 11 | 56 | ||||
Income tax expense included in comparable earnings | (268 | ) | (234 | ) | ||
Net income attributable to non-controlling interests included in comparable earnings | (86 | ) | (49 | ) | ||
Preferred share dividends | (41 | ) | (40 | ) | ||
Comparable earnings | 946 | 719 |
• | higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher flow-through taxes and incentive earnings |
• | higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform |
• | higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017 |
• | higher revenues from Mexico Natural Gas Pipelines as a result of changes in timing of revenue recognition |
• | lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days. |
• | changes in comparable EBITDA described above |
• | higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018 |
• | higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities |
• | lower interest income and other as a result of realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. |
TransCanada Management's discussion and analysis 2018 | 107 |
• | a $722 million non-cash asset impairment charge related to Bison |
• | a $79 million non-cash goodwill impairment charge related to Tuscarora |
• | $130 million of termination payments received on two of Bison’s transportation contracts which was recorded in Revenues. |
• | increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service and additional contract sales on ANR and Great Lakes |
• | increased earnings due to the amortization of the net regulatory liabilities recognized in 2017, partially offset by a reduction in certain rates on Columbia Gas, as a result of U.S. Tax Reform. |
• | higher revenues from operations as a result of changes in timing of revenue recognition |
• | equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The interest expense on this inter-affiliate loan is fully offset in Interest income and other in the Corporate segment |
• | incremental earnings from a CRE tariff increase. |
108 | TransCanada Management's discussion and analysis 2018 |
• | a $1,256 million pre-tax impairment charge in 2017 for the Energy East pipeline and related projects |
• | $11 million of pre-tax costs in 2017 related to Keystone XL for the maintenance and liquidation of project assets which were expensed pending further advancement of the project |
• | unrealized gains from changes in the fair value of derivatives related to our liquids marketing business. |
• | higher contracted and uncontracted volumes on the Keystone Pipeline System |
• | higher contribution from liquids marketing activities from improved margins and volumes |
• | incremental contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017 |
• | lower business development costs as a result of capitalizing Keystone XL expenditures in 2018 |
• | a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent earnings from our U.S. operations. |
• | a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities |
• | a pre-tax net loss of $10 million related to our U.S. Northeast power marketing contracts. These results have been excluded from Energy's comparable earnings in 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020 |
• | a pre-tax gain in 2017 of $127 million related to the sale of our Ontario solar assets |
• | a pre-tax net gain of $15 million in 2017 related to the monetization of our U.S. Northeast power generation assets |
• | unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks. |
• | decreased earnings from Bruce Power primarily due to lower volumes resulting from higher outage days |
• | decreased Western and Eastern Power results due to the sales of our Cartier Wind power facilities in October 2018 and our Ontario solar assets in December 2017, partially offset by higher Western Power realized margins on higher generation volumes |
• | lower Natural Gas Storage results primarily due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities and resulted in lower realized natural gas storage price spreads. |
• | foreign exchange gains on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing. There is a corresponding foreign exchange loss included in Interest income and other on the inter-affiliate loan receivable which fully offsets this gain. |
TransCanada Management's discussion and analysis 2018 | 109 |
Units of measure | ||
Bbl/d | Barrel(s) per day | |
Bcf | Billion cubic feet | |
Bcf/d | Billion cubic feet per day | |
GWh | Gigawatt hours | |
km | Kilometres | |
MMcf/d | Million cubic feet per day | |
MW | Megawatt(s) | |
MWh | Megawatt hours | |
PJ/d | Petajoule per day | |
TJ/d | Terajoule per day | |
General terms and terms related to our operations | ||
ATM | An at-the-market program allowing us to issue common shares from treasury at the prevailing market price | |
bitumen | A thick, heavy oil that must be diluted to flow (also see: diluent). One of the components of the oil sands, along with sand, water and clay | |
cogeneration facilities | Facilities that produce both electricity and useful heat at the same time | |
diluent | A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines | |
DRP | Dividend reinvestment plan | |
Empress | A major delivery/receipt point for natural gas near the Alberta/Saskatchewan border | |
FID | Final investment decision | |
force majeure | Unforeseeable circumstances that prevent a party to a contract from fulfilling it | |
GHG | Greenhouse gas | |
HSSE | Health, safety, sustainability and environment | |
investment base | Includes rate base as well as assets under construction | |
LDC | Local distribution company | |
LNG | Liquefied natural gas | |
LTAA | Long Term Adjustment Account | |
MLP | Master limited partnership | |
OM&A | Operating, maintenance and administration | |
PPA | Power purchase arrangement | |
rate base | Average assets in service, working capital and deferred amounts used in setting of regulated rates | |
TOMS | TransCanada Operational Management System | |
TSA | Transportation Service Agreement | |
WCSB | Western Canada Sedimentary Basin |
Accounting terms | ||
AFUDC | Allowance for funds used during construction | |
AOCI | Accumulated other comprehensive (loss)/income | |
FASB | Financial Accounting Standards Board (U.S.) | |
GAAP | U.S. generally accepted accounting principles | |
RRA | Rate-regulated accounting | |
ROE | Return on common equity | |
Government and regulatory bodies terms | ||
AER | Alberta Energy Regulator | |
CCIR | Carbon Competitiveness Incentive Regulation | |
CEPA | Canadian Energy Pipeline Association | |
CFE | Comisión Federal de Electricidad (Mexico) | |
CGA | Canadian Gas Association | |
CRE | Comisión Reguladora de Energia, or Energy Regulatory Commission (Mexico) | |
DOJ | U.S. Department of Justice | |
DOS | U.S. Department of State | |
FERC | Federal Energy Regulatory Commission (U.S.) | |
IESO | Independent Electricity System Operator | |
NEB | National Energy Board (Canada) | |
NYSE | New York Stock Exchange | |
OBPS | Output Based Pricing System | |
OPEC | Organization of the Petroleum Exporting Countries | |
OPG | Ontario Power Generation | |
PHMSA | Pipeline and Hazardous Materials Safety Administration | |
SEC | U.S. Securities and Exchange Commission | |
SDDENR | South Dakota Department of Environment and Natural Resources | |
SGER | Specified Gas Emitters Regulations (replaced by the CCIR) | |
TSX | Toronto Stock Exchange |
110 | TransCanada Management's discussion and analysis 2018 |
Russell K. Girling President and Chief Executive Officer | Donald R. Marchand Executive Vice-President and Chief Financial Officer | |
February 13, 2019 |
TransCanada Consolidated financial statements 2018 | 111 |
112 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 113 |
year ended December 31 | 2018 | 2017 | 2016 | |||||||||
(millions of Canadian $, except per share amounts) | ||||||||||||
Revenues (Note 5) | ||||||||||||
Canadian Natural Gas Pipelines | 4,038 | 3,693 | 3,682 | |||||||||
U.S. Natural Gas Pipelines | 4,314 | 3,584 | 2,526 | |||||||||
Mexico Natural Gas Pipelines | 619 | 570 | 378 | |||||||||
Liquids Pipelines | 2,584 | 2,009 | 1,755 | |||||||||
Energy | 2,124 | 3,593 | 4,206 | |||||||||
13,679 | 13,449 | 12,547 | ||||||||||
Income from Equity Investments (Note 9) | 714 | 773 | 514 | |||||||||
Operating and Other Expenses | ||||||||||||
Plant operating costs and other | 3,591 | 3,906 | 3,861 | |||||||||
Commodity purchases resold | 1,488 | 2,382 | 2,172 | |||||||||
Property taxes | 569 | 569 | 555 | |||||||||
Depreciation and amortization | 2,350 | 2,055 | 1,939 | |||||||||
Goodwill and other asset impairment charges (Notes 8, 11 and 12) | 801 | 1,257 | 1,388 | |||||||||
8,799 | 10,169 | 9,915 | ||||||||||
Gain/(Loss) on Assets Held for Sale/Sold (Note 26) | 170 | 631 | (833 | ) | ||||||||
Financial Charges | ||||||||||||
Interest expense (Note 17) | 2,265 | 2,069 | 1,998 | |||||||||
Allowance for funds used during construction | (526 | ) | (507 | ) | (419 | ) | ||||||
Interest income and other | 76 | (184 | ) | (103 | ) | |||||||
1,815 | 1,378 | 1,476 | ||||||||||
Income before Income Taxes | 3,949 | 3,306 | 837 | |||||||||
Income Tax Expense/(Recovery) (Note 16) | ||||||||||||
Current | 315 | 149 | 156 | |||||||||
Deferred | 284 | 566 | 196 | |||||||||
Deferred – U.S. Tax Reform and 2018 FERC Actions | (167 | ) | (804 | ) | — | |||||||
432 | (89 | ) | 352 | |||||||||
Net Income | 3,517 | 3,395 | 485 | |||||||||
Net (loss)/income attributable to non-controlling interests (Note 19) | (185 | ) | 238 | 252 | ||||||||
Net Income Attributable to Controlling Interests | 3,702 | 3,157 | 233 | |||||||||
Preferred share dividends | 163 | 160 | 109 | |||||||||
Net Income Attributable to Common Shares | 3,539 | 2,997 | 124 | |||||||||
Net Income per Common Share (Note 20) | ||||||||||||
Basic | $3.92 | $3.44 | $0.16 | |||||||||
Diluted | $3.92 | $3.43 | $0.16 | |||||||||
Dividends Declared per Common Share | $2.76 | $2.50 | $2.26 | |||||||||
Weighted Average Number of Common Shares (millions) (Note 20) | ||||||||||||
Basic | 902 | 872 | 759 | |||||||||
Diluted | 903 | 874 | 760 |
114 | TransCanada Consolidated financial statements 2018 |
year ended December 31 | 2018 | 2017 | 2016 | |||
(millions of Canadian $) | ||||||
Net Income | 3,517 | 3,395 | 485 | |||
Other Comprehensive Income/(Loss), Net of Income Taxes | ||||||
Foreign currency translation gains and losses on net investment in foreign operations | 1,358 | (749 | ) | 3 | ||
Reclassification of foreign currency translation gains on disposal of foreign operations | — | (77 | ) | — | ||
Change in fair value of net investment hedges | (42 | ) | — | (10 | ) | |
Change in fair value of cash flow hedges | (10 | ) | 3 | 30 | ||
Reclassification to net income of gains and losses on cash flow hedges | 21 | (2 | ) | 42 | ||
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | (114 | ) | (11 | ) | (26 | ) |
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 15 | 16 | 16 | |||
Other comprehensive income/(loss) on equity investments | 86 | (106 | ) | (87 | ) | |
Other comprehensive income/(loss) (Note 22) | 1,314 | (926 | ) | (32 | ) | |
Comprehensive Income | 4,831 | 2,469 | 453 | |||
Comprehensive (loss)/income attributable to non-controlling interests | (13 | ) | 83 | 241 | ||
Comprehensive Income Attributable to Controlling Interests | 4,844 | 2,386 | 212 | |||
Preferred share dividends | 163 | 160 | 109 | |||
Comprehensive Income Attributable to Common Shares | 4,681 | 2,226 | 103 |
TransCanada Consolidated financial statements 2018 | 115 |
year ended December 31 | 2018 | 2017 | 2016 | ||||||
(millions of Canadian $) | |||||||||
Cash Generated from Operations | |||||||||
Net income | 3,517 | 3,395 | 485 | ||||||
Depreciation and amortization | 2,350 | 2,055 | 1,939 | ||||||
Goodwill and other asset impairment charges (Notes 8, 11 and 12) | 801 | 1,257 | 1,388 | ||||||
Deferred income taxes (Note 16) | 284 | 566 | 196 | ||||||
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 16) | (167 | ) | (804 | ) | — | ||||
Income from equity investments (Note 9) | (714 | ) | (773 | ) | (514 | ) | |||
Distributions received from operating activities of equity investments (Note 9) | 985 | 970 | 844 | ||||||
Employee post-retirement benefits funding, net of expense (Note 23) | (35 | ) | (64 | ) | (3 | ) | |||
(Gain)/loss on assets held for sale/sold (Note 26) | (170 | ) | (631 | ) | 833 | ||||
Equity allowance for funds used during construction | (374 | ) | (362 | ) | (253 | ) | |||
Unrealized losses/(gains) on financial instruments | 220 | (149 | ) | (149 | ) | ||||
Other | (40 | ) | 43 | 55 | |||||
(Increase)/decrease in operating working capital (Note 25) | (102 | ) | (273 | ) | 248 | ||||
Net cash provided by operations | 6,555 | 5,230 | 5,069 | ||||||
Investing Activities | |||||||||
Capital expenditures (Note 4) | (9,418 | ) | (7,383 | ) | (5,007 | ) | |||
Capital projects in development (Note 4) | (496 | ) | (146 | ) | (295 | ) | |||
Contributions to equity investments (Notes 4 and 9) | (1,015 | ) | (1,681 | ) | (765 | ) | |||
Acquisitions, net of cash acquired | — | — | (13,608 | ) | |||||
Proceeds from sales of assets, net of transaction costs | 614 | 4,683 | 6 | ||||||
Reimbursement of costs related to capital projects in development (Note 12) | 470 | 634 | — | ||||||
Other distributions from equity investments (Note 9) | 121 | 362 | 727 | ||||||
Deferred amounts and other | (295 | ) | (168 | ) | 159 | ||||
Net cash used in investing activities | (10,019 | ) | (3,699 | ) | (18,783 | ) | |||
Financing Activities | |||||||||
Notes payable issued/(repaid), net | 817 | 1,038 | (329 | ) | |||||
Long-term debt issued, net of issue costs | 6,238 | 3,643 | 12,333 | ||||||
Long-term debt repaid | (3,550 | ) | (7,085 | ) | (7,153 | ) | |||
Junior subordinated notes issued, net of issue costs | — | 3,468 | 1,549 | ||||||
Dividends on common shares | (1,571 | ) | (1,339 | ) | (1,436 | ) | |||
Dividends on preferred shares | (158 | ) | (155 | ) | (100 | ) | |||
Distributions to non-controlling interests | (225 | ) | (283 | ) | (279 | ) | |||
Common shares issued, net of issue costs | 1,148 | 274 | 7,747 | ||||||
Common shares repurchased (Note 20) | — | — | (14 | ) | |||||
Preferred shares issued, net of issue costs | — | — | 1,474 | ||||||
Partnership units of TC PipeLines, LP issued, net of issue costs | 49 | 225 | 215 | ||||||
Common units of Columbia Pipeline Partners LP acquired | — | (1,205 | ) | — | |||||
Net cash provided by/(used in) financing activities | 2,748 | (1,419 | ) | 14,007 | |||||
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents | 73 | (39 | ) | (127 | ) | ||||
(Decrease)/Increase in Cash and Cash Equivalents | (643 | ) | 73 | 166 | |||||
Cash and Cash Equivalents | |||||||||
Beginning of year | 1,089 | 1,016 | 850 | ||||||
Cash and Cash Equivalents | |||||||||
End of year | 446 | 1,089 | 1,016 |
116 | TransCanada Consolidated financial statements 2018 |
at December 31 | 2018 | 2017 | |||||
(millions of Canadian $) | |||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | 446 | 1,089 | |||||
Accounts receivable | 2,535 | 2,522 | |||||
Inventories | 431 | 378 | |||||
Assets held for sale (Note 6) | 543 | — | |||||
Other (Note 7) | 1,180 | 691 | |||||
5,135 | 4,680 | ||||||
Plant, Property and Equipment (Note 8) | 66,503 | 57,277 | |||||
Equity Investments (Note 9) | 7,113 | 6,366 | |||||
Regulatory Assets (Note 10) | 1,548 | 1,376 | |||||
Goodwill (Note 11) | 14,178 | 13,084 | |||||
Loan Receivable from Affiliate (Note 9) | 1,315 | 919 | |||||
Intangible and Other Assets (Note 12) | 1,921 | 1,484 | |||||
Restricted Investments | 1,207 | 915 | |||||
98,920 | 86,101 | ||||||
LIABILITIES | |||||||
Current Liabilities | |||||||
Notes payable (Note 13) | 2,762 | 1,763 | |||||
Accounts payable and other (Note 14) | 5,408 | 4,057 | |||||
Dividends payable | 668 | 586 | |||||
Accrued interest | 646 | 605 | |||||
Current portion of long-term debt (Note 17) | 3,462 | 2,866 | |||||
12,946 | 9,877 | ||||||
Regulatory Liabilities (Note 10) | 3,930 | 4,321 | |||||
Other Long-Term Liabilities (Note 15) | 1,008 | 727 | |||||
Deferred Income Tax Liabilities (Note 16) | 6,026 | 5,403 | |||||
Long-Term Debt (Note 17) | 36,509 | 31,875 | |||||
Junior Subordinated Notes (Note 18) | 7,508 | 7,007 | |||||
67,927 | 59,210 | ||||||
EQUITY | |||||||
Common shares, no par value (Note 20) | 23,174 | 21,167 | |||||
Issued and outstanding: | December 31, 2018 – 918 million shares | ||||||
December 31, 2017 – 881 million shares | |||||||
Preferred shares (Note 21) | 3,980 | 3,980 | |||||
Additional paid-in capital | 17 | — | |||||
Retained earnings | 2,773 | 1,623 | |||||
Accumulated other comprehensive loss (Note 22) | (606 | ) | (1,731 | ) | |||
Controlling Interests | 29,338 | 25,039 | |||||
Non-controlling interests (Note 19) | 1,655 | 1,852 | |||||
30,993 | 26,891 | ||||||
98,920 | 86,101 |
Russell K. Girling, Director | John E. Lowe, Director |
TransCanada Consolidated financial statements 2018 | 117 |
year ended December 31 | 2018 | 2017 | 2016 | ||||||
(millions of Canadian $) | |||||||||
Common Shares (Note 20) | |||||||||
Balance at beginning of year | 21,167 | 20,099 | 12,102 | ||||||
Shares issued: | |||||||||
Under at-the-market equity issuance program, net of issue costs | 1,118 | 216 | — | ||||||
Under dividend reinvestment and share purchase plan | 855 | 790 | 177 | ||||||
On exercise of stock options | 34 | 62 | 74 | ||||||
Under public offerings, net of issue costs | — | — | 7,752 | ||||||
Shares repurchased | — | — | (6 | ) | |||||
Balance at end of year | 23,174 | 21,167 | 20,099 | ||||||
Preferred Shares | |||||||||
Balance at beginning of year | 3,980 | 3,980 | 2,499 | ||||||
Shares issued under public offerings, net of issue costs | — | — | 1,481 | ||||||
Balance at end of year | 3,980 | 3,980 | 3,980 | ||||||
Additional Paid-In Capital | |||||||||
Balance at beginning of year | — | — | 7 | ||||||
Issuance of stock options, net of exercises | 10 | 6 | 6 | ||||||
Dilution from TC PipeLines, LP units issued | 7 | 26 | 24 | ||||||
Asset drop-downs to TC PipeLines, LP | — | (202 | ) | (38 | ) | ||||
Columbia Pipeline Partners LP acquisition | — | (171 | ) | — | |||||
Common shares repurchased (Note 20) | — | — | (8 | ) | |||||
Reclassification of additional paid-in capital deficit to retained earnings | — | 341 | 9 | ||||||
Balance at end of year | 17 | — | — | ||||||
Retained Earnings | |||||||||
Balance at beginning of year | 1,623 | 1,138 | 2,769 | ||||||
Net income attributable to controlling interests | 3,702 | 3,157 | 233 | ||||||
Common share dividends | (2,501 | ) | (2,184 | ) | (1,733 | ) | |||
Preferred share dividends | (163 | ) | (159 | ) | (122 | ) | |||
Adjustment related to income tax effects of asset drop-downs to TC PipeLines, LP (Note 3) | 95 | — | — | ||||||
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform (Note 3) | 17 | — | — | ||||||
Adjustment related to employee share-based payments | — | 12 | — | ||||||
Reclassification of additional paid-in capital deficit to retained earnings | — | (341 | ) | (9 | ) | ||||
Balance at end of year | 2,773 | 1,623 | 1,138 | ||||||
Accumulated Other Comprehensive Loss | |||||||||
Balance at beginning of year | (1,731 | ) | (960 | ) | (939 | ) | |||
Other comprehensive income/(loss) attributable to controlling interests (Note 22) | 1,142 | (771 | ) | (21 | ) | ||||
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform (Note 3) | (17 | ) | — | — | |||||
Balance at end of year | (606 | ) | (1,731 | ) | (960 | ) | |||
Equity Attributable to Controlling Interests | 29,338 | 25,039 | 24,257 | ||||||
Equity Attributable to Non-Controlling Interests | |||||||||
Balance at beginning of year | 1,852 | 1,726 | 1,717 | ||||||
Net (loss)/income attributable to non-controlling interests | (185 | ) | 238 | 252 | |||||
Other comprehensive income/(loss) attributable to non-controlling interests | 172 | (155 | ) | (11 | ) | ||||
Issuance of TC PipeLines, LP units | |||||||||
Proceeds, net of issue costs | 49 | 225 | 215 | ||||||
Decrease in TransCanada's ownership of TC PipeLines, LP | (9 | ) | (41 | ) | (40 | ) | |||
Distributions declared to non-controlling interests | (224 | ) | (280 | ) | (279 | ) | |||
Reclassification from/(to) common units subject to rescission or redemption (Note 19) | — | 106 | (1,179 | ) | |||||
Impact of Columbia Pipeline Partners LP acquisition | — | 33 | — | ||||||
Acquisition of non-controlling interests in Columbia Pipeline Partners LP | — | — | 1,051 | ||||||
Balance at end of year | 1,655 | 1,852 | 1,726 | ||||||
Total Equity | 30,993 | 26,891 | 25,983 |
118 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 119 |
• | fair value of plant, property and equipment and equity investments (Notes 8 and 9) |
• | fair value of goodwill (Note 11) |
• | fair value of intangible assets (Note 12) and |
• | fair value of assets and liabilities acquired in a business combination (Note 26). |
• | depreciation rates of plant, property and equipment (Note 8) |
• | carrying value of regulatory assets and liabilities (Note 10) |
• | carrying value of asset retirement obligations (Note 15) |
• | provisions for income taxes, including U.S. Tax Reform (Note 16) |
• | assumptions used to measure retirement and other post-retirement obligations (Note 23) |
• | fair value of financial instruments (Note 24) and |
• | provisions for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28). |
• | a regulator must establish or approve the rates for the regulated services or activities |
• | the regulated rates must be designed to recover the cost of providing the services or products and |
• | it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct or indirect competition. |
120 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 121 |
122 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 123 |
• | when the asset is expected to be retired |
• | the scope and cost of abandonment and reclamation activities that are required and |
• | appropriate inflation and discount rates. |
124 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 125 |
126 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 127 |
128 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 129 |
130 | TransCanada Consolidated financial statements 2018 |
year ended December 31, 2018 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | Energy | Corporate1 | Total | |||||||||||||
(millions of Canadian $) | ||||||||||||||||||||
Revenues | 4,038 | 4,314 | 619 | 2,584 | 2,124 | — | 13,679 | |||||||||||||
Intersegment revenues | — | 162 | — | — | 56 | (218 | ) | 2 | — | |||||||||||
4,038 | 4,476 | 619 | 2,584 | 2,180 | (218 | ) | 13,679 | |||||||||||||
Income from equity investments | 12 | 256 | 22 | 64 | 355 | 5 | 3 | 714 | ||||||||||||
Plant operating costs and other | (1,405 | ) | (1,368 | ) | (34 | ) | (630 | ) | (313 | ) | 159 | 2 | (3,591 | ) | ||||||
Commodity purchases resold | — | — | — | — | (1,488 | ) | — | (1,488 | ) | |||||||||||
Property taxes | (266 | ) | (199 | ) | — | (98 | ) | (6 | ) | — | (569 | ) | ||||||||
Depreciation and amortization | (1,129 | ) | (664 | ) | (97 | ) | (341 | ) | (119 | ) | — | (2,350 | ) | |||||||
Goodwill and other asset impairment charges | — | (801 | ) | — | — | — | — | (801 | ) | |||||||||||
Gain on sale of assets | — | — | — | — | 170 | — | 170 | |||||||||||||
Segmented earnings/(losses) | 1,250 | 1,700 | 510 | 1,579 | 779 | (54 | ) | 5,764 | ||||||||||||
Interest expense | (2,265 | ) | ||||||||||||||||||
Allowance for funds used during construction | 526 | |||||||||||||||||||
Interest income and other3 | (76 | ) | ||||||||||||||||||
Income before income taxes | 3,949 | |||||||||||||||||||
Income tax expense | (432 | ) | ||||||||||||||||||
Net income | 3,517 | |||||||||||||||||||
Net loss attributable to non-controlling interests | 185 | |||||||||||||||||||
Net income attributable to controlling interests | 3,702 | |||||||||||||||||||
Preferred share dividends | (163 | ) | ||||||||||||||||||
Net income attributable to common shares | 3,539 | |||||||||||||||||||
Capital spending | ||||||||||||||||||||
Capital expenditures | 2,442 | 5,591 | 463 | 110 | 767 | 45 | 9,418 | |||||||||||||
Capital projects in development | 36 | 1 | — | 459 | — | — | 496 | |||||||||||||
Contributions to equity investments | — | 179 | 334 | 12 | 490 | — | 1,015 | |||||||||||||
2,478 | 5,771 | 797 | 581 | 1,257 | 45 | 10,929 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
3 | Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further information. |
TransCanada Consolidated financial statements 2018 | 131 |
year ended December 31, 2017 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | Energy | Corporate1 | Total | |||||||||||||
(millions of Canadian $) | ||||||||||||||||||||
Revenues | 3,693 | 3,584 | 570 | 2,009 | 3,593 | — | 13,449 | |||||||||||||
Intersegment revenues | — | 51 | — | — | — | (51 | ) | 2 | — | |||||||||||
3,693 | 3,635 | 570 | 2,009 | 3,593 | (51 | ) | 13,449 | |||||||||||||
Income/(loss) from equity investments | 11 | 240 | (9 | ) | (3 | ) | 471 | 63 | 3 | 773 | ||||||||||
Plant operating costs and other | (1,300 | ) | (1,340 | ) | (42 | ) | (623 | ) | (550 | ) | (51 | ) | 2 | (3,906 | ) | |||||
Commodity purchases resold | — | — | — | — | (2,382 | ) | — | (2,382 | ) | |||||||||||
Property taxes | (260 | ) | (181 | ) | — | (89 | ) | (39 | ) | — | (569 | ) | ||||||||
Depreciation and amortization | (908 | ) | (594 | ) | (93 | ) | (309 | ) | (151 | ) | — | (2,055 | ) | |||||||
Goodwill and other asset impairment charges | — | — | — | (1,236 | ) | (21 | ) | — | (1,257 | ) | ||||||||||
Gain on sale of assets | — | — | — | — | 631 | — | 631 | |||||||||||||
Segmented earnings/(losses) | 1,236 | 1,760 | 426 | (251 | ) | 1,552 | (39 | ) | 4,684 | |||||||||||
Interest expense | (2,069 | ) | ||||||||||||||||||
Allowance for funds used during construction | 507 | |||||||||||||||||||
Interest income and other3 | 184 | |||||||||||||||||||
Income before income taxes | 3,306 | |||||||||||||||||||
Income tax recovery | 89 | |||||||||||||||||||
Net income | 3,395 | |||||||||||||||||||
Net income attributable to non-controlling interests | (238 | ) | ||||||||||||||||||
Net income attributable to controlling interests | 3,157 | |||||||||||||||||||
Preferred share dividends | (160 | ) | ||||||||||||||||||
Net income attributable to common shares | 2,997 | |||||||||||||||||||
Capital spending | ||||||||||||||||||||
Capital expenditures | 2,106 | 3,712 | 833 | 341 | 350 | 41 | 7,383 | |||||||||||||
Capital projects in development | 75 | — | — | 71 | — | — | 146 | |||||||||||||
Contributions to equity investments | — | 118 | 1,121 | 117 | 325 | — | 1,681 | |||||||||||||
2,181 | 3,830 | 1,954 | 529 | 675 | 41 | 9,210 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
3 | Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further information. |
132 | TransCanada Consolidated financial statements 2018 |
year ended December 31, 2016 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | Energy | Corporate1 | Total | |||||||||||||
(millions of Canadian $) | ||||||||||||||||||||
Revenues | 3,682 | 2,526 | 378 | 1,755 | 4,206 | — | 12,547 | |||||||||||||
Intersegment revenues | — | 56 | — | — | — | (56 | ) | 2 | — | |||||||||||
3,682 | 2,582 | 378 | 1,755 | 4,206 | (56 | ) | 12,547 | |||||||||||||
Income/(loss) from equity investments | 12 | 214 | (3 | ) | (1 | ) | 292 | — | 514 | |||||||||||
Plant operating costs and other | (1,245 | ) | (1,057 | ) | (43 | ) | (568 | ) | (884 | ) | (64 | ) | 2 | (3,861 | ) | |||||
Commodity purchases resold | — | — | — | — | (2,172 | ) | — | (2,172 | ) | |||||||||||
Property taxes | (267 | ) | (120 | ) | — | (88 | ) | (80 | ) | — | (555 | ) | ||||||||
Depreciation and amortization | (875 | ) | (425 | ) | (45 | ) | (292 | ) | (302 | ) | — | (1,939 | ) | |||||||
Goodwill and other asset impairment charges | — | — | — | — | (1,388 | ) | — | (1,388 | ) | |||||||||||
Loss on assets held for sale/sold | — | (4 | ) | — | — | (829 | ) | — | (833 | ) | ||||||||||
Segmented earnings/(losses) | 1,307 | 1,190 | 287 | 806 | (1,157 | ) | (120 | ) | 2,313 | |||||||||||
Interest expense | (1,998 | ) | ||||||||||||||||||
Allowance for funds used during construction | 419 | |||||||||||||||||||
Interest income and other | 103 | |||||||||||||||||||
Income before income taxes | 837 | |||||||||||||||||||
Income tax expense | (352 | ) | ||||||||||||||||||
Net income | 485 | |||||||||||||||||||
Net income attributable to non-controlling interests | (252 | ) | ||||||||||||||||||
Net income attributable to controlling interests | 233 | |||||||||||||||||||
Preferred share dividends | (109 | ) | ||||||||||||||||||
Net income attributable to common shares | 124 | |||||||||||||||||||
Capital spending | ||||||||||||||||||||
Capital expenditures | 1,372 | 1,517 | 944 | 668 | 473 | 33 | 5,007 | |||||||||||||
Capital projects in development | 153 | — | — | 142 | — | — | 295 | |||||||||||||
Contributions to equity investments | — | 5 | 198 | 327 | 235 | — | 765 | |||||||||||||
1,525 | 1,522 | 1,142 | 1,137 | 708 | 33 | 6,067 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
TransCanada Consolidated financial statements 2018 | 133 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Total Assets by segment | |||||
Canadian Natural Gas Pipelines | 18,407 | 16,904 | |||
U.S. Natural Gas Pipelines | 44,115 | 35,898 | |||
Mexico Natural Gas Pipelines | 7,058 | 5,716 | |||
Liquids Pipelines | 17,352 | 15,438 | |||
Energy | 8,475 | 8,503 | |||
Corporate | 3,513 | 3,642 | |||
98,920 | 86,101 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Revenues | ||||||||
Canada – domestic | 4,187 | 3,618 | 3,697 | |||||
Canada – export | 1,075 | 1,255 | 1,177 | |||||
United States | 7,798 | 8,006 | 7,295 | |||||
Mexico | 619 | 570 | 378 | |||||
13,679 | 13,449 | 12,547 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Plant, Property and Equipment | |||||
Canada | 23,226 | 21,632 | |||
United States | 37,385 | 30,693 | |||
Mexico | 5,892 | 4,952 | |||
66,503 | 57,277 |
134 | TransCanada Consolidated financial statements 2018 |
(millions of Canadian $) | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | Energy | Total | ||||||
Revenues from contracts with customers | ||||||||||||
Capacity arrangements and transportation | 4,038 | 3,549 | 614 | 2,079 | — | 10,280 | ||||||
Power generation | — | — | — | — | 1,771 | 1,771 | ||||||
Natural gas storage and other | — | 654 | 5 | 3 | 81 | 743 | ||||||
4,038 | 4,203 | 619 | 2,082 | 1,852 | 12,794 | |||||||
Other revenues1,2 | — | 111 | — | 502 | 272 | 885 | ||||||
4,038 | 4,314 | 619 | 2,584 | 2,124 | 13,679 |
1 | Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 24, Risk management and financial instruments, for further information on income from financial instruments. |
2 | Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 16, Income taxes, for further information. |
TransCanada Consolidated financial statements 2018 | 135 |
As reported | Adjustment | |||||
(millions of Canadian $) | December 31, 2017 | January 1, 2018 | ||||
Current Assets | ||||||
Accounts receivable | 2,522 | (62 | ) | 2,460 | ||
Other1 | 691 | 79 | 770 | |||
Current Liabilities | ||||||
Accounts payable and other2 | 4,057 | 17 | 4,074 |
1 | Adjustment relates to contract assets previously included in Accounts receivable. |
2 | Adjustment relates to contract liabilities previously included in Accounts receivable. |
December 31, 2018 | |||||
As reported | Pro-forma using legacy U.S. GAAP | ||||
(millions of Canadian $) | |||||
Current Assets | |||||
Accounts receivable | 2,535 | 2,694 | |||
Other | 1,180 | 1,021 |
(millions of Canadian $) | December 31, 2018 | January 1, 2018 | ||||
Receivables from contracts with customers | 1,684 | 1,736 | ||||
Contract assets1 | 159 | 79 | ||||
Long-term contract assets2 | 21 | — | ||||
Contract liabilities3 | 11 | 17 | ||||
Long-term contract liabilities4 | 121 | — |
1 | Recorded as part of Other current assets on the Consolidated balance sheet. |
2 | Recorded as part of Intangibles and other assets on the Consolidated balance sheet. |
3 | Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2018, |
4 | Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet. |
136 | TransCanada Consolidated financial statements 2018 |
1. | The original expected duration of the contract is one year or less. |
2. | The Company recognizes revenue from the contract that is equal to the amount invoiced, where the amount invoiced represents the value to the customer of the service performed to date. This is referred to as the "right to invoice" practical expedient. |
3. | The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time. |
TransCanada Consolidated financial statements 2018 | 137 |
(millions of Canadian $) | |||
Assets held for sale | |||
Accounts receivable | 6 | ||
Plant, property and equipment | 537 | ||
Total assets held for sale | 543 | ||
Liabilities related to assets held for sale | |||
Other long-term liabilities | (3 | ) | |
Total liabilities related to assets held for sale1 | (3 | ) |
1 | Included in Accounts payable and other on the Consolidated balance sheet. |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Fair value of derivative contracts (Note 24) | 737 | 332 | |||
Contract assets (Note 5) | 159 | — | |||
Regulatory assets (Note 10) | 83 | 23 | |||
Cash provided as collateral | 55 | 99 | |||
Prepaid expenses | 41 | 109 | |||
Other | 105 | 128 | |||
1,180 | 691 |
138 | TransCanada Consolidated financial statements 2018 |
2018 | 2017 | ||||||||||||||||
at December 31 | Cost | Accumulated Depreciation | Net Book Value | Cost | Accumulated Depreciation | Net Book Value | |||||||||||
(millions of Canadian $) | |||||||||||||||||
Canadian Natural Gas Pipelines | |||||||||||||||||
NGTL System | |||||||||||||||||
Pipeline | 10,764 | 4,500 | 6,264 | 10,153 | 4,190 | 5,963 | |||||||||||
Compression | 3,289 | 1,677 | 1,612 | 3,021 | 1,593 | 1,428 | |||||||||||
Metering and other | 1,247 | 613 | 634 | 1,188 | 569 | 619 | |||||||||||
15,300 | 6,790 | 8,510 | 14,362 | 6,352 | 8,010 | ||||||||||||
Under construction | 2,111 | — | 2,111 | 940 | — | 940 | |||||||||||
17,411 | 6,790 | 10,621 | 15,302 | 6,352 | 8,950 | ||||||||||||
Canadian Mainline | |||||||||||||||||
Pipeline | 10,077 | 6,777 | 3,300 | 9,763 | 6,455 | 3,308 | |||||||||||
Compression | 3,642 | 2,656 | 986 | 3,605 | 2,499 | 1,106 | |||||||||||
Metering and other | 652 | 241 | 411 | 655 | 207 | 448 | |||||||||||
14,371 | 9,674 | 4,697 | 14,023 | 9,161 | 4,862 | ||||||||||||
Under construction | 149 | — | 149 | 156 | — | 156 | |||||||||||
14,520 | 9,674 | 4,846 | 14,179 | 9,161 | 5,018 | ||||||||||||
Other Canadian Natural Gas Pipelines1 | |||||||||||||||||
Other | 1,842 | 1,420 | 422 | 1,815 | 1,363 | 452 | |||||||||||
Under construction | 124 | — | 124 | 4 | — | 4 | |||||||||||
1,966 | 1,420 | 546 | 1,819 | 1,363 | 456 | ||||||||||||
33,897 | 17,884 | 16,013 | 31,300 | 16,876 | 14,424 | ||||||||||||
U.S. Natural Gas Pipelines | |||||||||||||||||
Columbia Gas | |||||||||||||||||
Pipeline | 6,711 | 251 | 6,460 | 3,550 | 125 | 3,425 | |||||||||||
Compression | 2,932 | 132 | 2,800 | 1,547 | 64 | 1,483 | |||||||||||
Metering and other | 2,884 | 75 | 2,809 | 2,306 | 37 | 2,269 | |||||||||||
12,527 | 458 | 12,069 | 7,403 | 226 | 7,177 | ||||||||||||
Under construction | 4,347 | — | 4,347 | 3,332 | — | 3,332 | |||||||||||
16,874 | 458 | 16,416 | 10,735 | 226 | 10,509 | ||||||||||||
ANR | |||||||||||||||||
Pipeline | 1,600 | 443 | 1,157 | 1,427 | 365 | 1,062 | |||||||||||
Compression | 1,978 | 388 | 1,590 | 1,582 | 286 | 1,296 | |||||||||||
Metering and other | 1,217 | 324 | 893 | 961 | 268 | 693 | |||||||||||
4,795 | 1,155 | 3,640 | 3,970 | 919 | 3,051 | ||||||||||||
Under construction | 272 | — | 272 | 358 | — | 358 | |||||||||||
5,067 | 1,155 | 3,912 | 4,328 | 919 | 3,409 | ||||||||||||
TransCanada Consolidated financial statements 2018 | 139 |
2018 | 2017 | ||||||||||||||||
at December 31 | Cost | Accumulated Depreciation | Net Book Value | Cost | Accumulated Depreciation | Net Book Value | |||||||||||
(millions of Canadian $) | |||||||||||||||||
Other U.S. Natural Gas Pipelines | |||||||||||||||||
GTN | 2,322 | 951 | 1,371 | 2,107 | 822 | 1,285 | |||||||||||
Great Lakes | 2,180 | 1,251 | 929 | 1,988 | 1,113 | 875 | |||||||||||
Columbia Gulf | 1,753 | 74 | 1,679 | 1,115 | 37 | 1,078 | |||||||||||
Midstream | 1,212 | 91 | 1,121 | 1,085 | 54 | 1,031 | |||||||||||
Other2 | 1,190 | 474 | 716 | 1,950 | 574 | 1,376 | |||||||||||
8,657 | 2,841 | 5,816 | 8,245 | 2,600 | 5,645 | ||||||||||||
Under construction | 846 | — | 846 | 699 | — | 699 | |||||||||||
9,503 | 2,841 | 6,662 | 8,944 | 2,600 | 6,344 | ||||||||||||
31,444 | 4,454 | 26,990 | 24,007 | 3,745 | 20,262 | ||||||||||||
Mexico Natural Gas Pipelines | |||||||||||||||||
Pipeline | 3,172 | 301 | 2,871 | 2,872 | 214 | 2,658 | |||||||||||
Compression | 506 | 41 | 465 | 448 | 30 | 418 | |||||||||||
Metering and other | 640 | 91 | 549 | 573 | 65 | 508 | |||||||||||
4,318 | 433 | 3,885 | 3,893 | 309 | 3,584 | ||||||||||||
Under construction | 1,990 | — | 1,990 | 1,368 | — | 1,368 | |||||||||||
6,308 | 433 | 5,875 | 5,261 | 309 | 4,952 | ||||||||||||
Liquids Pipelines | |||||||||||||||||
Keystone Pipeline System | |||||||||||||||||
Pipeline | 9,780 | 1,271 | 8,509 | 9,002 | 992 | 8,010 | |||||||||||
Pumping equipment | 1,065 | 184 | 881 | 1,022 | 152 | 870 | |||||||||||
Tanks and other3 | 3,598 | 488 | 3,110 | 3,314 | 385 | 2,929 | |||||||||||
14,443 | 1,943 | 12,500 | 13,338 | 1,529 | 11,809 | ||||||||||||
Under construction4 | 18 | — | 18 | 456 | — | 456 | |||||||||||
14,461 | 1,943 | 12,518 | 13,794 | 1,529 | 12,265 | ||||||||||||
Intra-Alberta Pipelines5 | |||||||||||||||||
Pipeline | 762 | 22 | 740 | 748 | 3 | 745 | |||||||||||
Pumping equipment | 104 | 3 | 101 | 104 | — | 104 | |||||||||||
Tanks and other | 291 | 8 | 283 | 259 | 1 | 258 | |||||||||||
1,157 | 33 | 1,124 | 1,111 | 4 | 1,107 | ||||||||||||
Under construction | 84 | — | 84 | 47 | — | 47 | |||||||||||
1,241 | 33 | 1,208 | 1,158 | 4 | 1,154 | ||||||||||||
15,702 | 1,976 | 13,726 | 14,952 | 1,533 | 13,419 | ||||||||||||
Energy | |||||||||||||||||
Natural Gas6 | 2,062 | 708 | 1,354 | 2,645 | 743 | 1,902 | |||||||||||
Wind7 | — | — | — | 673 | 204 | 469 | |||||||||||
Natural Gas Storage and Other | 741 | 169 | 572 | 734 | 156 | 578 | |||||||||||
2,803 | 877 | 1,926 | 4,052 | 1,103 | 2,949 | ||||||||||||
Under construction | 1,735 | — | 1,735 | 1,028 | — | 1,028 | |||||||||||
4,538 | 877 | 3,661 | 5,080 | 1,103 | 3,977 | ||||||||||||
Corporate | 448 | 210 | 238 | 411 | 168 | 243 | |||||||||||
92,337 | 25,834 | 66,503 | 81,011 | 23,734 | 57,277 |
140 | TransCanada Consolidated financial statements 2018 |
1 | Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink. |
2 | Includes Portland, North Baja, Tuscarora and Crossroads as well as Bison for 2017. Bison's remaining carrying value was fully impaired at December 31, 2018. |
3 | Includes tanks that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $194 million and $23 million, respectively, at December 31, 2018 (2017 – $184 million and $19 million, respectively), while revenues of $15 million were recognized in 2018 (2017 – $16 million; 2016 – $16 million). |
4 | Certain costs related to the Keystone XL project were recorded in Plant, property and equipment at December 31, 2017. In 2018, these costs were reclassified to Capital projects in development as the Company recommenced capitalizing Keystone XL development costs. |
5 | Includes Northern Courier and White Spruce. Northern Courier is accounted for as an operating lease and was placed in service on November 1, 2017. The cost and accumulated depreciation of this facility were $1,130 million and $32 million, respectively, at December 31, 2018 (2017 – $1,111 million and $4 million, respectively), while revenues of $142 million were recognized in 2018 (2017 – $20 million). |
6 | Includes Coolidge, Grandview, Bécancour, Halton Hills and the Alberta cogeneration natural gas-fired facilities. Coolidge, Grandview and Bécancour have long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $655 million and $268 million, respectively, at December 31, 2018 (2017 – $1,264 million and $354 million, respectively). At December 31, 2018, the cost and accumulated depreciation of Coolidge were reclassified to Assets held for sale. Refer to Note 6, Assets held for sale, for further information. Revenues of $216 million were recognized in 2018 (2017 – $215 million; 2016 – $212 million) through the sale of electricity under the related PPAs for these assets. |
7 | The Company closed the sale of its Cartier Wind power assets on October 24, 2018. Refer to Note 26, Acquisitions and dispositions, for further information. |
TransCanada Consolidated financial statements 2018 | 141 |
(millions of Canadian $) | Ownership Interest at December 31, 2018 | Income/(Loss) from Equity Investments | Equity Investments | ||||||||||||||
year ended December 31 | at December 31 | ||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | |||||||||||||
Canadian Natural Gas Pipelines | |||||||||||||||||
TQM | 50.0 | % | 12 | 11 | 12 | 71 | 68 | ||||||||||
U.S. Natural Gas Pipelines | |||||||||||||||||
Northern Border1 | 50.0 | % | 87 | 87 | 92 | 677 | 641 | ||||||||||
Iroquois2 | 50.0 | % | 60 | 59 | 54 | 291 | 280 | ||||||||||
Millennium3 | 47.5 | % | 75 | 66 | 33 | 511 | 291 | ||||||||||
Pennant Midstream3 | 47.0 | % | 17 | 11 | 6 | 256 | 228 | ||||||||||
Other | Various | 17 | 17 | 29 | 113 | 92 | |||||||||||
Mexico Natural Gas Pipelines | |||||||||||||||||
Sur de Texas4 | 60.0 | % | 27 | 66 | (3 | ) | 627 | 399 | |||||||||
TransGas | nil | — | (12 | ) | — | — | — | ||||||||||
Liquids Pipelines | |||||||||||||||||
Grand Rapids5 | 50.0 | % | 65 | 17 | (1 | ) | 1,028 | 996 | |||||||||
Other6 | Various | (1 | ) | (20 | ) | — | 21 | 20 | |||||||||
Energy | |||||||||||||||||
Bruce Power7 | 48.3 | % | 311 | 434 | 293 | 3,166 | 2,987 | ||||||||||
Portlands Energy8 | 50.0 | % | 36 | 31 | 33 | 289 | 301 | ||||||||||
ASTC Power Partnership | 50.0 | % | — | — | (37 | ) | — | — | |||||||||
Other | Various | 8 | 6 | 3 | 63 | 63 | |||||||||||
714 | 773 | 514 | 7,113 | 6,366 |
1 | At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$115 million (2017 – US$115 million) due to the fair value assessment of assets at the time of acquisition. |
2 | At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million (2017 – US$41 million) due mainly to the fair value assessment of the assets at the time of acquisition. |
3 | Acquired as part of Columbia Pipeline Group, Inc. (Columbia) on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition. |
4 | TransCanada has an ownership interest of 60.0 per cent in Sur de Texas which, as a jointly controlled entity, applies the equity method of accounting. Income from equity investments includes foreign exchange gains and losses recorded in the Corporate segment which are fully offset in Interest income and other in the Consolidated statement of income. |
5 | Grand Rapids was placed in service in August 2017. At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $102 million (2017 – $105 million) due mainly to interest capitalized during construction and the fair value of guarantees. |
6 | Includes investments in Canaport Energy East Marine Terminal Limited Partnership and HoustonLink Pipeline Company LLC. At December 31, 2018 and 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil. |
7 | At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $870 million (2017 – $902 million) due to the fair value assessment of assets at the time of acquisitions. |
8 | At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million (2017 – $73 million) due mainly to interest capitalized during construction. |
142 | TransCanada Consolidated financial statements 2018 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Income | ||||||||
Revenues | 4,836 | 4,913 | 4,336 | |||||
Operating and other expenses | (3,545 | ) | (2,993 | ) | (3,068 | ) | ||
Net income | 1,515 | 1,636 | 1,080 | |||||
Net income attributable to TransCanada | 714 | 773 | 514 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Balance Sheet | |||||
Current assets | 2,209 | 2,176 | |||
Non-current assets | 20,647 | 17,869 | |||
Current liabilities | (2,049 | ) | (1,577 | ) | |
Non-current liabilities | (9,042 | ) | (8,217 | ) |
TransCanada Consolidated financial statements 2018 | 143 |
144 | TransCanada Consolidated financial statements 2018 |
TransCanada Consolidated financial statements 2018 | 145 |
at December 31 | 2018 | 2017 | Remaining Recovery/ Settlement Period (years) | |||||
(millions of Canadian $) | ||||||||
Regulatory Assets | ||||||||
Deferred income taxes1 | 1,051 | 940 | n/a | |||||
Operating and debt-service regulatory assets2 | 12 | — | 1 | |||||
Pensions and other post-retirement benefits1,3 | 379 | 388 | n/a | |||||
Foreign exchange on long-term debt1,4 | 46 | — | 1-11 | |||||
Other | 143 | 71 | n/a | |||||
1,631 | 1,399 | |||||||
Less: Current portion included in Other current assets (Note 7) | 83 | 23 | ||||||
1,548 | 1,376 | |||||||
Regulatory Liabilities | ||||||||
Operating and debt-service regulatory liabilities2 | 96 | 188 | 1 | |||||
Pensions and other post-retirement benefits3 | 53 | 164 | n/a | |||||
ANR related post-employment and retirement benefits other than pension5 | 54 | 66 | n/a | |||||
Long term adjustment account6 | 1,015 | 1,142 | 2-45 | |||||
Bridging amortization account6 | 305 | 202 | 12 | |||||
Pipeline abandonment trust balance | 1,113 | 825 | n/a | |||||
Cost of removal7 | 261 | 216 | n/a | |||||
Deferred income taxes | 165 | 75 | n/a | |||||
Deferred income taxes – U.S. Tax Reform8 | 1,394 | 1,659 | n/a | |||||
Other | 65 | 47 | n/a | |||||
4,521 | 4,584 | |||||||
Less: Current portion included in Accounts payable and other (Note 14) | 591 | 263 | ||||||
3,930 | 4,321 |
1 | These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period. |
2 | Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulator for inclusion in determining tolls for the following calendar year. |
3 | These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. |
4 | Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. |
5 | This balance represents the amount ANR estimates it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved September 2016 rate settlement, $11 million (US$8 million) of the regulatory liability balance at December 31, 2018 (2017 – $26 million; US$21 million) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $43 million (US$32 million) balance accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time. |
6 | These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. The 2018 LTAA balance of $1,015 million consists of $932 million to be amortized over two years with the remaining balance to be amortized over 45 years. |
7 | This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred. |
8 | These balances represent the impact of U.S. Tax Reform. The regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. See Note 16, Income taxes, for further information on U.S. Tax Reform. |
146 | TransCanada Consolidated financial statements 2018 |
(millions of Canadian $) | U.S. Natural Gas Pipelines | |
Balance at January 1, 2017 | 13,958 | |
Columbia adjustment (Note 26) | 71 | |
Foreign exchange rate changes | (945 | ) |
Balance at December 31, 2017 | 13,084 | |
Tuscarora impairment charge | (79 | ) |
Foreign exchange rate changes | 1,173 | |
Balance at December 31, 2018 | 14,178 |
TransCanada Consolidated financial statements 2018 | 147 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Capital projects in development | 1,051 | 596 | |||
Deferred income tax assets (Note 16) | 322 | 316 | |||
Employee post-retirement benefits (Note 23) | 192 | 193 | |||
Fair value of derivative contracts (Note 24) | 61 | 73 | |||
Other | 295 | 306 | |||
1,921 | 1,484 |
148 | TransCanada Consolidated financial statements 2018 |
2018 | 2017 | ||||||||||
(millions of Canadian $, unless otherwise noted) | Outstanding at December 31 | Weighted Average Interest Rate per Annum at December 31 | Outstanding at December 31 | Weighted Average Interest Rate per Annum at December 31 | |||||||
Canada | 2,117 | 2.5 | % | 884 | 1.6 | % | |||||
U.S. (2018 – US$448; 2017 – US$688) | 611 | 3.1 | % | 862 | 2.2 | % | |||||
Mexico (2018 – US$25; 2017 – MXN$275) | 34 | 3.3 | % | 17 | 8.0 | % | |||||
2,762 | 1,763 |
at December 31 | |||||||||||||
(billions of Canadian $, unless otherwise noted) | 2018 | 2017 | |||||||||||
Borrower | Description | Matures | Total Facilities | Unused Capacity | Total Facilities | ||||||||
Committed, syndicated, revolving, extendible, senior unsecured credit facilities1: | |||||||||||||
TCPL | Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes | December 2023 | 3.0 | 3.0 | 3.0 | ||||||||
TCPL/TCPL USA/Columbia/TAIL | Supports TCPL, TCPL USA and TAIL's U.S. dollar commercial paper programs and is used for general corporate purposes of the borrowers, guaranteed by TCPL | December 2019 | US 4.5 | US 4.5 | — | ||||||||
TCPL/TCPL USA/Columbia/TAIL | Used for general corporate purposes of the borrowers, guaranteed by TCPL | December 2021 | US 1.0 | US 1.0 | — | ||||||||
TCPL | Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes | — | — | US 2.0 | |||||||||
TCPL USA | Used for TCPL USA general corporate purposes, guaranteed by TCPL | — | — | US 1.0 | |||||||||
Columbia | Used for Columbia general corporate purposes, guaranteed by TCPL | — | — | US 1.0 | |||||||||
TAIL | Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL | — | — | US 0.5 | |||||||||
Demand senior unsecured revolving credit facilities1: | |||||||||||||
TCPL/TCPL USA | Supports the issuance of letters of credit and provides additional liquidity, TCPL USA facility guaranteed by TCPL | Demand | 2.1 | 1.0 | 1.9 | ||||||||
Mexico subsidiary | Used for Mexico general corporate purposes, guaranteed by TCPL | Demand | MXN 5.0 | MXN 4.5 | MXN 5.0 |
1 | Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2018, the Company was in compliance with all debt covenants. |
TransCanada Consolidated financial statements 2018 | 149 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Trade payables | 3,224 | 2,847 | |||
Fair value of derivative contracts (Note 24) | 922 | 387 | |||
Unredeemed shares of Columbia | 357 | 312 | |||
Regulatory liabilities (Note 10) | 591 | 263 | |||
Other | 314 | 248 | |||
5,408 | 4,057 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Employee post-retirement benefits (Note 23) | 569 | 389 | |||
Asset retirement obligations | 90 | 98 | |||
Fair value of derivative contracts (Note 24) | 42 | 72 | |||
Guarantees (Note 27) | 12 | 16 | |||
Other | 295 | 152 | |||
1,008 | 727 |
150 | TransCanada Consolidated financial statements 2018 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Current | ||||||||
Canada | 65 | 113 | 116 | |||||
Foreign | 250 | 36 | 40 | |||||
315 | 149 | 156 | ||||||
Deferred | ||||||||
Canada | 49 | (185 | ) | 101 | ||||
Foreign | 235 | 751 | 95 | |||||
Foreign – U.S. Tax Reform and 2018 FERC Actions | (167 | ) | (804 | ) | — | |||
117 | (238 | ) | 196 | |||||
Income Tax Expense/(Recovery) | 432 | (89 | ) | 352 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Canada | 433 | (339 | ) | 219 | ||||
Foreign | 3,516 | 3,645 | 618 | |||||
Income before Income Taxes | 3,949 | 3,306 | 837 |
TransCanada Consolidated financial statements 2018 | 151 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Income before income taxes | 3,949 | 3,306 | 837 | |||||
Federal and provincial statutory tax rate | 27 | % | 27 | % | 27 | % | ||
Expected income tax expense | 1,066 | 893 | 226 | |||||
U.S. Tax Reform and 2018 FERC Actions | (167 | ) | (804 | ) | — | |||
Foreign income tax rate differentials | (432 | ) | (81 | ) | (196 | ) | ||
Loss/(income) from equity investments and non-controlling interests | 50 | (64 | ) | (68 | ) | |||
Income tax differential related to regulated operations | (54 | ) | (42 | ) | 81 | |||
Non-taxable portion of capital gains | (11 | ) | (42 | ) | — | |||
Asset impairment charges1 | — | 34 | 242 | |||||
Non-deductible amounts | — | 4 | 46 | |||||
Other | (20 | ) | 13 | 21 | ||||
Income Tax Expense/(Recovery) | 432 | (89 | ) | 352 |
1 | Net of nil (2017 – nil, 2016 – $112 million) attributed to higher foreign tax rates. |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Deferred Income Tax Assets | |||||
Tax loss and credit carryforwards | 1,238 | 1,379 | |||
Difference in accounting and tax bases of impaired assets and assets held for sale | 574 | 651 | |||
Regulatory and other deferred amounts | 858 | 512 | |||
Unrealized foreign exchange losses on long-term debt | 491 | 216 | |||
Financial instruments | — | 10 | |||
Other | 292 | 227 | |||
3,453 | 2,995 | ||||
Less: valuation allowance | 1,159 | 832 | |||
2,294 | 2,163 | ||||
Deferred Income Tax Liabilities | |||||
Difference in accounting and tax bases of plant, property and equipment and PPAs | 6,449 | 6,240 | |||
Equity investments | 1,069 | 632 | |||
Taxes on future revenue requirement | 300 | 238 | |||
Other | 180 | 140 | |||
7,998 | 7,250 | ||||
Net Deferred Income Tax Liabilities | 5,704 | 5,087 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Deferred Income Tax Assets | |||||
Intangible and other assets (Note 12) | 322 | 316 | |||
Deferred Income Tax Liabilities | |||||
Deferred income tax liabilities | 6,026 | 5,403 | |||
Net Deferred Income Tax Liabilities | 5,704 | 5,087 |
152 | TransCanada Consolidated financial statements 2018 |
at December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Unrecognized tax benefit at beginning of year | 15 | 18 | 17 | |||||
Gross increases – tax positions in prior years | 13 | — | 3 | |||||
Gross decreases – tax positions in prior years | (5 | ) | (1 | ) | — | |||
Gross increases – tax positions in current year | — | 2 | 2 | |||||
Settlement | — | — | (1 | ) | ||||
Lapse of statutes of limitations | (4 | ) | (4 | ) | (3 | ) | ||
Unrecognized Tax Benefit at End of Year | 19 | 15 | 18 |
TransCanada Consolidated financial statements 2018 | 153 |
2018 | 2017 | ||||||||||||
Outstanding amounts | Maturity Dates | Outstanding at December 31 | Interest Rate1 | Outstanding at December 31 | Interest Rate1 | ||||||||
(millions of Canadian $, unless otherwise noted) | |||||||||||||
TRANSCANADA PIPELINES LIMITED | |||||||||||||
Debentures | |||||||||||||
Canadian | 2019 to 2020 | 350 | 11.4 | % | 500 | 10.8 | % | ||||||
U.S. (2018 and 2017 – US$400) | 2021 | 546 | 9.9 | % | 501 | 9.9 | % | ||||||
Medium Term Notes | |||||||||||||
Canadian | 2019 to 2048 | 7,504 | 4.8 | % | 6,504 | 4.9 | % | ||||||
Senior Unsecured Notes | |||||||||||||
U.S. (2018 – US$17,192; 2017 – US$14,892) | 2019 to 2049 | 23,456 | 5.1 | % | 18,644 | 5.1 | % | ||||||
31,856 | 26,149 | ||||||||||||
NOVA GAS TRANSMISSION LTD. | |||||||||||||
Debentures and Notes | |||||||||||||
Canadian | 2024 | 100 | 9.9 | % | 100 | 9.9 | % | ||||||
U.S. (2018 and 2017 – US$200) | 2023 | 273 | 7.9 | % | 250 | 7.9 | % | ||||||
Medium Term Notes | |||||||||||||
Canadian | 2025 to 2030 | 504 | 7.4 | % | 504 | 7.4 | % | ||||||
U.S. (2018 and 2017 – US$33) | 2026 | 44 | 7.5 | % | 41 | 7.5 | % | ||||||
921 | 895 | ||||||||||||
COLUMBIA PIPELINE GROUP, INC. | |||||||||||||
Senior Unsecured Notes | |||||||||||||
U.S. (2018 – US$2,250; 2017 – US$2,750)2 | 2020 to 2045 | 3,070 | 4.4 | % | 3,443 | 4.0 | % | ||||||
TC PIPELINES, LP | |||||||||||||
Unsecured Loan Facility | |||||||||||||
U.S. (2018 – US$40; 2017 – US$185) | 2021 | 55 | 3.8 | % | 232 | 2.7 | % | ||||||
Unsecured Term Loan | |||||||||||||
U.S. (2018 – US$500; 2017 – US$670)3 | 2022 | 682 | 3.6 | % | 839 | 2.7 | % | ||||||
Senior Unsecured Notes | |||||||||||||
U.S. (2018 and 2017 – US$1,200) | 2021 to 2027 | 1,637 | 4.4 | % | 1,502 | 4.4 | % | ||||||
2,374 | 2,573 | ||||||||||||
ANR PIPELINE COMPANY | |||||||||||||
Senior Unsecured Notes | |||||||||||||
U.S. (2018 and 2017 – US$672) | 2021 to 2026 | 918 | 7.2 | % | 842 | 7.2 | % | ||||||
GAS TRANSMISSION NORTHWEST LLC | |||||||||||||
Unsecured Term Loan | |||||||||||||
U.S. (2018 – US$35; 2017 – US$55) | 2019 | 48 | 3.3 | % | 69 | 1.1 | % | ||||||
Senior Unsecured Notes | |||||||||||||
U.S. (2018 and 2017 – US$250) | 2020 to 2035 | 341 | 5.6 | % | 313 | 5.6 | % | ||||||
389 | 382 | ||||||||||||
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | |||||||||||||
Senior Unsecured Notes | |||||||||||||
U.S. (2018 – US$240; 2017 – US$259) | 2021 to 2030 | 327 | 7.7 | % | 324 | 7.7 | % |
154 | TransCanada Consolidated financial statements 2018 |
2018 | 2017 | ||||||||||||
Outstanding amounts | Maturity Dates | Outstanding at December 31 | Interest Rate1 | Outstanding at December 31 | Interest Rate1 | ||||||||
(millions of Canadian $, unless otherwise noted) | |||||||||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | |||||||||||||
Unsecured Loan Facility | |||||||||||||
U.S. (2018 – US$19; 2017 – nil) | 2023 | 26 | 3.6 | % | — | — | |||||||
Senior Secured Notes4 | |||||||||||||
U.S. (2018 – nil; 2017 – US$30) | — | — | 38 | 6.0 | % | ||||||||
26 | 38 | ||||||||||||
TUSCARORA GAS TRANSMISSION COMPANY | |||||||||||||
Unsecured Term Loan | |||||||||||||
U.S. (2018 – US$24; 2017 – US$25) | 2020 | 33 | 3.5 | % | 31 | 1.1 | % | ||||||
NORTH BAJA PIPELINE, LLC | |||||||||||||
Unsecured Term Loan | |||||||||||||
U.S. (2018 – US$50; 2017 – nil) | 2021 | 68 | 3.5 | % | — | — | |||||||
39,982 | 34,677 | ||||||||||||
Current portion of long-term debt | (3,462 | ) | (2,866 | ) | |||||||||
Unamortized debt discount and issue costs | (241 | ) | (174 | ) | |||||||||
Fair value adjustments5 | 230 | 238 | |||||||||||
36,509 | 31,875 |
1 | Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premium and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates. |
2 | Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest. |
3 | The US$500 million term loan facility was amended in September 2017 to extend the maturity dates from 2018 to 2022. |
4 | These notes were secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements. |
5 | The fair value adjustments include $232 million (2017 – $242 million) related to the acquisition of Columbia. The fair value adjustments also include a decrease of $2 million (2017 – $4 million) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information. |
(millions of Canadian $) | 2019 | 2020 | 2021 | 2022 | 2023 | |||||
Principal repayments on long-term debt | 3,465 | 2,834 | 2,098 | 2,100 | 1,930 |
TransCanada Consolidated financial statements 2018 | 155 |
(millions of Canadian $, unless otherwise noted) | ||||||||||||
Company | Issue Date | Type | Maturity Date | Amount | Interest Rate | |||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||||
October 2018 | Senior Unsecured Notes | March 2049 | US 1,000 | 5.10 | % | |||||||
October 2018 | Senior Unsecured Notes | May 2028 | US 400 | 4.25 | % | 1 | ||||||
July 2018 | Medium Term Notes | July 2048 | 800 | 4.18 | % | |||||||
July 2018 | Medium Term Notes | March 2028 | 200 | 3.39 | % | 2 | ||||||
May 2018 | Senior Unsecured Notes | May 2028 | US 1,000 | 4.25 | % | |||||||
May 2018 | Senior Unsecured Notes | May 2048 | US 1,000 | 4.875 | % | |||||||
May 2018 | Senior Unsecured Notes | May 2038 | US 500 | 4.75 | % | |||||||
November 2017 | Senior Unsecured Notes | November 2019 | US 550 | Floating | ||||||||
November 2017 | Senior Unsecured Notes | November 2019 | US 700 | 2.125 | % | |||||||
September 2017 | Medium Term Notes | March 2028 | 300 | 3.39 | % | |||||||
September 2017 | Medium Term Notes | September 2047 | 700 | 4.33 | % | |||||||
June 2016 | Acquisition Bridge Facility3 | June 2018 | US 5,213 | Floating | ||||||||
June 2016 | Medium Term Notes | July 2023 | 300 | 3.69 | % | 4 | ||||||
June 2016 | Medium Term Notes | June 2046 | 700 | 4.35 | % | |||||||
January 2016 | Senior Unsecured Notes | January 2026 | US 850 | 4.875 | % | |||||||
January 2016 | Senior Unsecured Notes | January 2019 | US 400 | 3.125 | % | |||||||
NORTH BAJA PIPELINE, LLC | ||||||||||||
December 2018 | Unsecured Term Loan | December 2021 | US 50 | Floating | ||||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | ||||||||||||
April 2018 | Unsecured Loan Facility | April 2023 | US 19 | Floating | ||||||||
TUSCARORA GAS TRANSMISSION COMPANY | ||||||||||||
August 2017 | Unsecured Term Loan | August 2020 | US 25 | Floating | ||||||||
April 2016 | Unsecured Term Loan | April 2019 | US 10 | Floating | ||||||||
TC PIPELINES, LP | ||||||||||||
May 2017 | Senior Unsecured Notes | May 2027 | US 500 | 3.90 | % | |||||||
TRANSCANADA PIPELINE USA LTD. | ||||||||||||
June 2016 | Acquisition Bridge Facility3 | June 2018 | US 1,700 | Floating | ||||||||
ANR PIPELINE COMPANY | ||||||||||||
June 2016 | Senior Unsecured Notes | June 2026 | US 240 | 4.14 | % |
1 | Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent. |
2 | Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent. |
3 | These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in second quarter 2017. |
4 | Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent. |
156 | TransCanada Consolidated financial statements 2018 |
(millions of Canadian $, unless otherwise noted) | ||||||||||
Company | Retirement/Repayment Date | Type | Amount | Interest Rate | ||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||
August 2018 | Senior Unsecured Notes | US 850 | 6.50 | % | ||||||
March 2018 | Debentures | 150 | 9.45 | % | ||||||
January 2018 | Senior Unsecured Notes | US 500 | 1.875 | % | ||||||
January 2018 | Senior Unsecured Notes | US 250 | Floating | |||||||
December 2017 | Debentures | 100 | 9.80 | % | ||||||
November 2017 | Senior Unsecured Notes | US 1,000 | 1.625 | % | ||||||
June 2017 | Acquisition Bridge Facility1 | US 1,513 | Floating | |||||||
February 2017 | Acquisition Bridge Facility1 | US 500 | Floating | |||||||
January 2017 | Medium Term Notes | 300 | 5.10 | % | ||||||
November 2016 | Acquisition Bridge Facility1 | US 3,200 | Floating | |||||||
October 2016 | Medium Term Notes | 400 | 4.65 | % | ||||||
June 2016 | Senior Unsecured Notes | US 84 | 7.69 | % | ||||||
June 2016 | Senior Unsecured Notes | US 500 | Floating | |||||||
January 2016 | Senior Unsecured Notes | US 750 | 0.75 | % | ||||||
TC PIPELINES, LP | ||||||||||
December 2018 | Unsecured Term Loan | US 170 | Floating | |||||||
COLUMBIA PIPELINE GROUP, INC. | ||||||||||
June 2018 | Senior Unsecured Notes | US 500 | 2.45 | % | ||||||
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | ||||||||||
May 2018 | Senior Secured Notes | US 18 | 5.90 | % | ||||||
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | ||||||||||
March 2018 | Senior Unsecured Notes | US 9 | 6.73 | % | ||||||
TUSCARORA GAS TRANSMISSION COMPANY | ||||||||||
August 2017 | Senior Secured Notes | US 12 | 3.82 | % | ||||||
TRANSCANADA PIPELINE USA LTD. | ||||||||||
June 2017 | Acquisition Bridge Facility1 | US 630 | Floating | |||||||
April 2017 | Acquisition Bridge Facility1 | US 1,070 | Floating | |||||||
NOVA GAS TRANSMISSION LTD. | ||||||||||
February 2016 | Debentures | 225 | 12.20 | % |
1 | These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in second quarter 2017. |
TransCanada Consolidated financial statements 2018 | 157 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Interest on long-term debt | 1,877 | 1,794 | 1,765 | |||||
Interest on junior subordinated notes | 391 | 348 | 180 | |||||
Interest on short-term debt | 73 | 33 | 18 | |||||
Capitalized interest | (124 | ) | (173 | ) | (176 | ) | ||
Amortization and other financial charges1 | 48 | 67 | 211 | |||||
2,265 | 2,069 | 1,998 |
1 | Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates. In 2016, this amount includes dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition. Refer to Note 20, Common shares, for further information. |
2018 | 2017 | ||||||||||||
Outstanding loan amount | Maturity Date | Outstanding at December 31 | Effective Interest Rate1 | Outstanding at December 31 | Effective Interest Rate1 | ||||||||
(millions of Canadian $, unless otherwise noted) | |||||||||||||
TRANSCANADA PIPELINES LIMITED2 | |||||||||||||
US$1,000 notes issued 2007 at 6.35%3 | 2067 | 1,364 | 5.6 | % | 1,252 | 5.0 | % | ||||||
US$750 notes issued 2015 at 5.875%4,5 | 2075 | 1,024 | 6.5 | % | 939 | 5.9 | % | ||||||
US$1,200 notes issued 2016 at 6.125%4,5 | 2076 | 1,637 | 7.2 | % | 1,502 | 6.6 | % | ||||||
US$1,500 notes issued 2017 at 5.55%4,5 | 2077 | 2,047 | 6.2 | % | 1,878 | 5.6 | % | ||||||
$1,500 notes issued 2017 at 4.90%4,5 | 2077 | 1,500 | 5.5 | % | 1,500 | 5.1 | % | ||||||
7,572 | 7,071 | ||||||||||||
Unamortized debt discount and issue costs | (64 | ) | (64 | ) | |||||||||
7,508 | 7,007 |
1 | The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for loan fees and discounts. |
2 | The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. |
3 | In May 2017, Junior subordinated notes of US$1 billion converted from a fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent. |
4 | The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. |
5 | The coupon rate is initially a fixed interest rate for the first ten years and converts to a floating rate thereafter. |
158 | TransCanada Consolidated financial statements 2018 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Non-controlling interest in TC PipeLines, LP | 1,655 | 1,852 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Non-controlling interest in TC PipeLines, LP | (185 | ) | 220 | 215 | ||||
Non-controlling interest in Portland Natural Gas Transmission System1 | — | 9 | 20 | |||||
Non-controlling interest in Columbia Pipeline Partners LP2 | — | 9 | 17 | |||||
(185 | ) | 238 | 252 |
1 | Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information. |
2 | Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP. |
TransCanada Consolidated financial statements 2018 | 159 |
Number of Shares | Amount | ||||
(thousands) | (millions of Canadian $) | ||||
Outstanding at January 1, 2016 | 702,614 | 12,102 | |||
Issued under public offerings1 | 156,825 | 7,752 | |||
Dividend reinvestment and share purchase plan | 2,942 | 177 | |||
Exercise of options | 1,683 | 74 | |||
Repurchase of shares | (305 | ) | (6 | ) | |
Outstanding at December 31, 2016 | 863,759 | 20,099 | |||
Dividend reinvestment and share purchase plan | 12,824 | 790 | |||
At-the-market equity issuance program1 | 3,462 | 216 | |||
Exercise of options | 1,331 | 62 | |||
Outstanding at December 31, 2017 | 881,376 | 21,167 | |||
At-the-market equity issuance program1 | 20,050 | 1,118 | |||
Dividend reinvestment and share purchase plan | 15,937 | 855 | |||
Exercise of options | 734 | 34 | |||
Outstanding at December 31, 2018 | 918,097 | 23,174 |
1 | Net of issue costs and deferred income taxes. |
160 | TransCanada Consolidated financial statements 2018 |
Weighted Average Common Shares Outstanding | ||||||||
(millions) | 2018 | 2017 | 2016 | |||||
Basic | 902 | 872 | 759 | |||||
Diluted | 903 | 874 | 760 |
TransCanada Consolidated financial statements 2018 | 161 |
Number of Options (thousands) | Weighted Average Exercise Prices | Weighted Average Remaining Contractual Life (years) | ||||
Options outstanding at January 1, 2018 | 11,026 | $51.38 | ||||
Options granted | 2,250 | $56.89 | ||||
Options exercised | (734 | ) | $42.65 | |||
Options forfeited/expired | (138 | ) | $57.23 | |||
Options Outstanding at December 31, 2018 | 12,404 | $52.83 | 3.6 | |||
Options Exercisable at December 31, 2018 | 8,189 | $50.72 | 2.6 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
Weighted average fair value | $5.80 | $7.22 | $5.67 | |||||
Expected life (years)1 | 5.7 | 5.7 | 5.8 | |||||
Interest rate | 2.1 | % | 1.2 | % | 0.7 | % | ||
Volatility2 | 16 | % | 18 | % | 21 | % | ||
Dividend yield | 4.2 | % | 3.6 | % | 4.9 | % | ||
Forfeiture rate3 | — | — | 5 | % |
1 | Expected life is based on historical exercise activity. |
2 | Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. |
3 | On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $, unless otherwise noted) | ||||||||
Total intrinsic value of options exercised | 10 | 28 | 31 | |||||
Fair value of options that have vested | 101 | 140 | 126 | |||||
Total options vested | 2.1 million | 2.3 million | 2.1 million |
162 | TransCanada Consolidated financial statements 2018 |
at December 31 | Number of Shares Outstanding | Current Yield | Annual Dividend Per Share | Redemption Price Per Share | Redemption and Conversion Option Date | Right to Convert Into1,2 | 2018 | 2017 | 2016 | |||||||||||||||
(thousands) | (millions of Canadian $)3 | |||||||||||||||||||||||
Cumulative First Preferred Shares | ||||||||||||||||||||||||
Series 1 | 9,498 | 3.266 | % | $0.8165 | $25.00 | December 31, 2019 | Series 2 | 233 | 233 | 233 | ||||||||||||||
Series 2 | 12,502 | Floating4 | Floating | $25.00 | December 31, 2019 | Series 1 | 306 | 306 | 306 | |||||||||||||||
Series 3 | 8,533 | 2.152 | % | $0.538 | $25.00 | June 30, 2020 | Series 4 | 209 | 209 | 209 | ||||||||||||||
Series 4 | 5,467 | Floating4 | Floating | $25.00 | June 30, 2020 | Series 3 | 134 | 134 | 134 | |||||||||||||||
Series 5 | 12,714 | 2.263 | % | $0.56575 | $25.00 | January 30, 2021 | Series 6 | 310 | 310 | 310 | ||||||||||||||
Series 6 | 1,286 | Floating4 | Floating | $25.00 | January 30, 2021 | Series 5 | 32 | 32 | 32 | |||||||||||||||
Series 7 | 24,000 | 4.00 | % | $1.00 | $25.00 | April 30, 2019 | Series 8 | 589 | 589 | 589 | ||||||||||||||
Series 9 | 18,000 | 4.25 | % | $1.0625 | $25.00 | October 30, 2019 | Series 10 | 442 | 442 | 442 | ||||||||||||||
Series 11 | 10,000 | 3.80 | % | $0.95 | $25.00 | November 30, 2020 | Series 12 | 244 | 244 | 244 | ||||||||||||||
Series 13 | 20,000 | 5.50 | % | $1.375 | $25.00 | May 31, 2021 | Series 14 | 493 | 493 | 493 | ||||||||||||||
Series 15 | 40,000 | 4.90 | % | $1.225 | $25.00 | May 31, 2022 | Series 16 | 988 | 988 | 988 | ||||||||||||||
Carrying value | 3,980 | 3,980 | 3,980 |
1 | Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate. |
2 | The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five-year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent, subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15). |
3 | Net of underwriting commissions and deferred income taxes. |
4 | The floating quarterly dividend rate for the Series 2 preferred shares is 3.633 per cent and for the Series 4 preferred shares is 2.993 per cent for the period starting December 31, 2018 to, but excluding, March 29, 2019. The floating quarterly dividend rate for the Series 6 preferred shares is 3.086 per cent for the period starting October 30, 2018 to, but excluding, January 30, 2019. These rates will reset each quarter going forward. |
TransCanada Consolidated financial statements 2018 | 163 |
year ended December 31, 2018 | Before Tax Amount | Income Tax Recovery/(Expense) | Net of Tax Amount | ||||||
(millions of Canadian $) | |||||||||
Foreign currency translation gains on net investment in foreign operations | 1,323 | 35 | 1,358 | ||||||
Change in fair value of net investment hedges | (57 | ) | 15 | (42 | ) | ||||
Change in fair value of cash flow hedges | (14 | ) | 4 | (10 | ) | ||||
Reclassification to net income of gains and losses on cash flow hedges | 27 | (6 | ) | 21 | |||||
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | (153 | ) | 39 | (114 | ) | ||||
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 20 | (5 | ) | 15 | |||||
Other comprehensive income on equity investments | 113 | (27 | ) | 86 | |||||
Other Comprehensive Income | 1,259 | 55 | 1,314 |
year ended December 31, 2017 | Before Tax Amount | Income Tax Recovery/(Expense) | Net of Tax Amount | ||||||
(millions of Canadian $) | |||||||||
Foreign currency translation losses on net investment in foreign operations | (746 | ) | (3 | ) | (749 | ) | |||
Reclassification of foreign currency translation gains on disposal of foreign operations | (77 | ) | — | (77 | ) | ||||
Change in fair value of cash flow hedges | 3 | — | 3 | ||||||
Reclassification to net income of gains and losses on cash flow hedges | (3 | ) | 1 | (2 | ) | ||||
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | (14 | ) | 3 | (11 | ) | ||||
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 21 | (5 | ) | 16 | |||||
Other comprehensive loss on equity investments | (141 | ) | 35 | (106 | ) | ||||
Other Comprehensive Loss | (957 | ) | 31 | (926 | ) |
year ended December 31, 2016 | Before Tax Amount | Income Tax Recovery/(Expense) | Net of Tax Amount | ||||||
(millions of Canadian $) | |||||||||
Foreign currency translation gains on net investment in foreign operations | 3 | — | 3 | ||||||
Change in fair value of net investment hedges | (14 | ) | 4 | (10 | ) | ||||
Change in fair value of cash flow hedges | 44 | (14 | ) | 30 | |||||
Reclassification to net income of gains and losses on cash flow hedges | 71 | (29 | ) | 42 | |||||
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans | (38 | ) | 12 | (26 | ) | ||||
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 22 | (6 | ) | 16 | |||||
Other comprehensive loss on equity investments | (117 | ) | 30 | (87 | ) | ||||
Other Comprehensive Loss | (29 | ) | (3 | ) | (32 | ) |
164 | TransCanada Consolidated financial statements 2018 |
Currency Translation Adjustments | Cash Flow Hedges | Pension and Other Post-Retirement Benefit Plan Adjustments | Equity Investments | Total1 | |||||||||||
AOCI balance at January 1, 2016 | (383 | ) | (97 | ) | (198 | ) | (261 | ) | (939 | ) | |||||
Other comprehensive income/(loss) before reclassifications2 | 7 | 27 | (26 | ) | (101 | ) | (93 | ) | |||||||
Amounts reclassified from AOCI | — | 42 | 16 | 14 | 72 | ||||||||||
Net current period other comprehensive income/(loss) | 7 | 69 | (10 | ) | (87 | ) | (21 | ) | |||||||
AOCI balance at December 31, 2016 | (376 | ) | (28 | ) | (208 | ) | (348 | ) | (960 | ) | |||||
Other comprehensive (loss)/income before reclassifications2,3 | (590 | ) | (1 | ) | (11 | ) | (117 | ) | (719 | ) | |||||
Amounts reclassified from AOCI | (77 | ) | (2 | ) | 16 | 11 | (52 | ) | |||||||
Net current period other comprehensive (loss)/income | (667 | ) | (3 | ) | 5 | (106 | ) | (771 | ) | ||||||
AOCI balance at December 31, 2017 | (1,043 | ) | (31 | ) | (203 | ) | (454 | ) | (1,731 | ) | |||||
Other comprehensive income/(loss) before reclassifications2 | 1,150 | (9 | ) | (114 | ) | 72 | 1,099 | ||||||||
Amounts reclassified from AOCI4,5 | — | 16 | 15 | 12 | 43 | ||||||||||
Net current period other comprehensive income/(loss) | 1,150 | 7 | (99 | ) | 84 | 1,142 | |||||||||
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform | — | 1 | (12 | ) | (6 | ) | (17 | ) | |||||||
AOCI balance at December 31, 2018 | 107 | (23 | ) | (314 | ) | (376 | ) | (606 | ) |
1 | All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. |
2 | In 2018, other comprehensive income before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interest gains of $166 million (2017 – $159 million losses; 2016 – $14 million losses) and losses of $1 million (2017 – $4 million gains and 2016 – $3 million gains), respectively. |
3 | Other comprehensive (loss)/income before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments. |
4 | Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $15 million ($11 million, net of tax) at December 31, 2018. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. |
5 | Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million and $2 million, respectively. |
TransCanada Consolidated financial statements 2018 | 165 |
Amounts Reclassified From AOCI1 | Affected Line Item in the Consolidated Statement of Income | ||||||||||
year ended December 31 | 2018 | 2017 | 2016 | ||||||||
(millions of Canadian $) | |||||||||||
Cash flow hedges | |||||||||||
Commodities | (4 | ) | 20 | (57 | ) | Revenues (Energy) | |||||
Interest | (18 | ) | (17 | ) | (14 | ) | Interest expense | ||||
(22 | ) | 3 | (71 | ) | Total before tax | ||||||
6 | (1 | ) | 29 | Income tax expense | |||||||
(16 | ) | 2 | (42 | ) | Net of tax1,3 | ||||||
Pension and other post-retirement benefit plan adjustments | |||||||||||
Amortization of actuarial gains and losses | (16 | ) | (15 | ) | (22 | ) | Plant operating costs and other2 | ||||
Settlement charge | (4 | ) | (2 | ) | — | Plant operating costs and other2 | |||||
(20 | ) | (17 | ) | (22 | ) | Total before tax | |||||
5 | 5 | 6 | Income tax expense | ||||||||
(15 | ) | (12 | ) | (16 | ) | Net of tax1 | |||||
Equity investments | |||||||||||
Equity income | (16 | ) | (15 | ) | (19 | ) | Income from equity investments | ||||
4 | 4 | 5 | Income tax expense | ||||||||
(12 | ) | (11 | ) | (14 | ) | Net of tax1,3 | |||||
Currency translation adjustments | |||||||||||
Realization of foreign currency translation gains on disposal of foreign operations | — | 77 | — | Gain/(loss) on assets held for sale/sold | |||||||
— | — | — | Income tax expense | ||||||||
— | 77 | — | Net of tax1 |
1 | Amounts in parentheses indicate expenses to the Consolidated statement of income. |
2 | These AOCI components are included in the computation of net benefit cost. Refer to Note 23, Employee post-retirement benefits for further information. |
3 | Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million (2017 – nil , 2016 – nil) and $2 million (2017 – nil, 2016 – nil), respectively. |
166 | TransCanada Consolidated financial statements 2018 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
DB Plans | 103 | 163 | 111 | |||||
Other post-retirement benefit plans | 23 | 7 | 8 | |||||
Savings and DC Plans | 59 | 42 | 52 | |||||
185 | 212 | 171 |
TransCanada Consolidated financial statements 2018 | 167 |
at December 31 | Pension Benefit Plans | Other Post-Retirement Benefit Plans | |||||||||
(millions of Canadian $) | 2018 | 2017 | 2018 | 2017 | |||||||
Change in Benefit Obligation1 | |||||||||||
Benefit obligation – beginning of year | 3,646 | 3,456 | 375 | 372 | |||||||
Service cost | 121 | 113 | 4 | 4 | |||||||
Interest cost | 134 | 135 | 14 | 14 | |||||||
Employee contributions | 5 | 5 | — | 3 | |||||||
Benefits paid | (177 | ) | (166 | ) | (23 | ) | (19 | ) | |||
Actuarial (gain)/loss | (92 | ) | 253 | 43 | 19 | ||||||
Curtailment | — | (14 | ) | — | (2 | ) | |||||
Settlement | (71 | ) | (66 | ) | — | — | |||||
Foreign exchange rate changes | 87 | (70 | ) | 17 | (16 | ) | |||||
Benefit obligation – end of year | 3,653 | 3,646 | 430 | 375 | |||||||
Change in Plan Assets | |||||||||||
Plan assets at fair value – beginning of year | 3,451 | 3,208 | 365 | 354 | |||||||
Actual return on plan assets | (73 | ) | 358 | (15 | ) | 45 | |||||
Employer contributions2 | 103 | 163 | 23 | 7 | |||||||
Employee contributions | 5 | 5 | — | 3 | |||||||
Benefits paid | (176 | ) | (166 | ) | (27 | ) | (19 | ) | |||
Settlement | (71 | ) | (57 | ) | — | — | |||||
Foreign exchange rate changes | 82 | (60 | ) | 30 | (25 | ) | |||||
Plan assets at fair value – end of year | 3,321 | 3,451 | 376 | 365 | |||||||
Funded Status – Plan Deficit | (332 | ) | (195 | ) | (54 | ) | (10 | ) |
1 | The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. |
2 | Excludes a $17 million letter of credit provided to the Canadian DB Plan for funding purposes (2017 – $27 million). |
168 | TransCanada Consolidated financial statements 2018 |
at December 31 | Pension Benefit Plans | Other Post-Retirement Benefit Plans | |||||||||
(millions of Canadian $) | 2018 | 2017 | 2018 | 2017 | |||||||
Intangible and other assets (Note 12) | — | — | 192 | 193 | |||||||
Accounts payable and other | (1 | ) | (1 | ) | (8 | ) | (8 | ) | |||
Other long-term liabilities (Note 15) | (331 | ) | (194 | ) | (238 | ) | (195 | ) | |||
(332 | ) | (195 | ) | (54 | ) | (10 | ) |
at December 31 | Pension Benefit Plans | Other Post-Retirement Benefit Plans | |||||||||
(millions of Canadian $) | 2018 | 2017 | 2018 | 2017 | |||||||
Projected benefit obligation1 | (3,653 | ) | (3,646 | ) | (246 | ) | (203 | ) | |||
Plan assets at fair value | 3,321 | 3,451 | — | — | |||||||
Funded Status – Plan Deficit | (332 | ) | (195 | ) | (246 | ) | (203 | ) |
1 | The projected benefit obligation for the pension benefit plans differ from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Accumulated benefit obligation | (3,347 | ) | (3,372 | ) | |
Plan assets at fair value | 3,321 | 3,451 | |||
Funded Status | (26 | ) | 79 |
at December 31 | 2018 | 2017 | |||
(millions of Canadian $) | |||||
Accumulated benefit obligation | (3,347 | ) | (944 | ) | |
Plan assets at fair value | 3,321 | 925 | |||
Funded Status – Plan Deficit | (26 | ) | (19 | ) |
Percentage of Plan Assets | Target Allocations | ||||||
at December 31 | 2018 | 2017 | 2018 | ||||
Debt securities | 33 | % | 30 | % | 25% to 45% | ||
Equity securities | 56 | % | 64 | % | 40% to 70% | ||
Alternatives | 11 | % | 6 | % | 5% to 15% | ||
100 | % | 100 | % |
TransCanada Consolidated financial statements 2018 | 169 |
at December 31 | Percentage of Plan Assets | ||||||||||
(millions of Canadian $) | 2018 | 2017 | 2018 | 2017 | |||||||
Debt securities | 8 | 7 | 0.3 | % | 0.2 | % | |||||
Equity securities | 7 | 3 | 0.2 | % | 0.1 | % |
170 | TransCanada Consolidated financial statements 2018 |
at December 31 | Quoted Prices in Active Markets (Level I) | Significant Other Observable Inputs (Level II) | Significant Unobservable Inputs (Level III) | Total | Percentage of Total Portfolio | ||||||||||||||||||||||
(millions of Canadian $) | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||||
Asset Category | |||||||||||||||||||||||||||
Cash and Cash Equivalents | 48 | 44 | — | 17 | — | — | 48 | 61 | 1 | 2 | |||||||||||||||||
Equity Securities: | |||||||||||||||||||||||||||
Canadian | 355 | 410 | 138 | 151 | — | — | 493 | 561 | 13 | 15 | |||||||||||||||||
U.S. | 460 | 543 | 116 | 354 | — | — | 576 | 897 | 16 | 24 | |||||||||||||||||
International | 40 | 45 | 281 | 322 | — | — | 321 | 367 | 9 | 10 | |||||||||||||||||
Global | 116 | — | 268 | 301 | — | — | 384 | 301 | 10 | 8 | |||||||||||||||||
Emerging | 8 | 8 | 138 | 147 | — | — | 146 | 155 | 4 | 4 | |||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||||||||
Canadian Bonds: | |||||||||||||||||||||||||||
Federal | — | — | 186 | 193 | — | — | 186 | 193 | 5 | 5 | |||||||||||||||||
Provincial | — | — | 198 | 194 | — | — | 198 | 194 | 5 | 5 | |||||||||||||||||
Municipal | — | — | 8 | 8 | — | — | 8 | 8 | 1 | — | |||||||||||||||||
Corporate | — | — | 112 | 122 | — | — | 112 | 122 | 3 | 3 | |||||||||||||||||
U.S. Bonds: | |||||||||||||||||||||||||||
Federal | 350 | — | — | 244 | — | — | 350 | 244 | 9 | 6 | |||||||||||||||||
State | — | — | — | 41 | — | — | — | 41 | — | 1 | |||||||||||||||||
Municipal | — | — | — | 4 | — | — | — | 4 | — | — | |||||||||||||||||
Corporate | 145 | — | 51 | 234 | — | — | 196 | 234 | 5 | 6 | |||||||||||||||||
International: | |||||||||||||||||||||||||||
Government | 6 | — | 4 | 4 | — | — | 10 | 4 | 1 | — | |||||||||||||||||
Corporate | 19 | — | 18 | 5 | — | — | 37 | 5 | 1 | — | |||||||||||||||||
Mortgage backed | 128 | — | — | 73 | — | — | 128 | 73 | 3 | 2 | |||||||||||||||||
Other Investments: | |||||||||||||||||||||||||||
Real estate | — | — | — | — | 196 | 140 | 196 | 140 | 5 | 4 | |||||||||||||||||
Infrastructure | — | — | — | — | 163 | 70 | 163 | 70 | 4 | 2 | |||||||||||||||||
Private equity funds | — | — | — | — | 3 | 6 | 3 | 6 | 1 | — | |||||||||||||||||
Funds held on deposit | 142 | 136 | — | — | — | — | 142 | 136 | 4 | 3 | |||||||||||||||||
1,817 | 1,186 | 1,518 | 2,414 | 362 | 216 | 3,697 | 3,816 | 100 | 100 |
(millions of Canadian $, pre-tax) | ||
Balance at December 31, 2016 | 199 | |
Purchases and sales | 11 | |
Realized and unrealized gains | 6 | |
Balance at December 31, 2017 | 216 | |
Purchases and sales | 127 | |
Realized and unrealized gains | 19 | |
Balance at December 31, 2018 | 362 |
TransCanada Consolidated financial statements 2018 | 171 |
(millions of Canadian $) | Pension Benefits | Other Post- Retirement Benefits | |||
2019 | 190 | 24 | |||
2020 | 193 | 23 | |||
2021 | 198 | 23 | |||
2022 | 203 | 23 | |||
2023 | 207 | 23 | |||
2024 to 2028 | 1,081 | 114 |
Pension Benefit Plans | Other Post-Retirement Benefit Plans | ||||||||||
at December 31 | 2018 | 2017 | 2018 | 2017 | |||||||
Discount rate | 3.90 | % | 3.60 | % | 4.10 | % | 3.70 | % | |||
Rate of compensation increase | 3.00 | % | 3.00 | % | — | — |
Pension Benefit Plans | Other Post-Retirement Benefit Plans | ||||||||||||||||
year ended December 31 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||
Discount rate | 3.60 | % | 3.95 | % | 4.20 | % | 3.70 | % | 4.15 | % | 4.30 | % | |||||
Expected long-term rate of return on plan assets | 6.70 | % | 6.50 | % | 6.70 | % | 4.00 | % | 6.05 | % | 5.95 | % | |||||
Rate of compensation increase | 3.00 | % | 1.20 | % | 0.80 | % | — | — | — |
(millions of Canadian $) | Increase | Decrease | |||
Effect on total of service and interest cost components | 1 | (1 | ) | ||
Effect on post-retirement benefit obligation | 25 | (21 | ) |
172 | TransCanada Consolidated financial statements 2018 |
at December 31 | Pension Benefit Plans | Other Post-Retirement Benefit Plans | |||||||||||||||
(millions of Canadian $) | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||
Service cost1 | 121 | 108 | 107 | 4 | 4 | 3 | |||||||||||
Other components of net benefit cost1 | |||||||||||||||||
Interest cost | 134 | 122 | 127 | 14 | 14 | 13 | |||||||||||
Expected return on plan assets | (221 | ) | (178 | ) | (175 | ) | (16 | ) | (21 | ) | (11 | ) | |||||
Amortization of actuarial loss | 15 | 14 | 20 | 1 | 1 | 2 | |||||||||||
Amortization of regulatory asset | 18 | 37 | 27 | — | 1 | 1 | |||||||||||
Amortization of transitional obligation related to regulated business | — | — | — | — | — | 2 | |||||||||||
Settlement charge – regulatory asset | — | 2 | — | — | — | — | |||||||||||
Settlement charge – AOCI | 4 | 2 | — | — | — | — | |||||||||||
(50 | ) | (1 | ) | (1 | ) | (1 | ) | (5 | ) | 7 | |||||||
Net Benefit Cost Recognized | 71 | 107 | 106 | 3 | (1 | ) | 10 |
1 | Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income. |
2018 | 2017 | 2016 | |||||||||||||||
at December 31 | Pension Benefits | Other Post- Retirement Benefits | Pension Benefits | Other Post- Retirement Benefits | Pension Benefits | Other Post- Retirement Benefits | |||||||||||
(millions of Canadian $) | |||||||||||||||||
Net loss | 364 | 53 | 273 | 11 | 270 | 21 |
2018 | 2017 | 2016 | |||||||||||||||
at December 31 | Pension Benefits | Other Post- Retirement Benefits | Pension Benefits | Other Post- Retirement Benefits | Pension Benefits | Other Post- Retirement Benefits | |||||||||||
(millions of Canadian $) | |||||||||||||||||
Amortization of net loss from AOCI to net income | (15 | ) | (1 | ) | (18 | ) | (1 | ) | (20 | ) | (2 | ) | |||||
Curtailment | — | — | (14 | ) | (2 | ) | — | — | |||||||||
Settlement | (4 | ) | — | (11 | ) | — | — | — | |||||||||
Funded status adjustment | 110 | 43 | 46 | (7 | ) | 43 | (5 | ) | |||||||||
91 | 42 | 3 | (10 | ) | 23 | (7 | ) |
TransCanada Consolidated financial statements 2018 | 173 |
• | Forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future |
• | Swaps – agreements between two parties to exchange streams of payments over time according to specified terms |
• | Options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. |
• | In the Company's power generation business, TransCanada manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets |
• | In the Company's non-regulated natural gas storage business, TransCanada's exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins |
• | In the Company's liquids marketing business, TransCanada enters into pipeline and storage terminal capacity contracts. TransCanada fixes a portion of its exposure on these contracts by entering into derivative instruments to manage its variable price fluctuations that arise from physical liquids transactions. |
174 | TransCanada Consolidated financial statements 2018 |
2018 | 2017 | ||||||||
at December 31 | Fair Value1,2 | Notional Amount | Fair Value1,2 | Notional Amount | |||||
(millions of Canadian $, unless otherwise noted) | |||||||||
U.S. dollar cross-currency interest rate swaps (maturing 2019)3 | (43 | ) | US 300 | (199 | ) | US 1,200 | |||
U.S. dollar foreign exchange options (maturing 2019 to 2020) | (47 | ) | US 2,500 | 5 | US 500 | ||||
(90 | ) | US 2,800 | (194 | ) | US 1,700 |
1 | Fair value equals carrying value. |
2 | No amounts have been excluded from the assessment of hedge effectiveness. |
3 | In 2018, Net income includes net realized gains of $2 million (2017 – gains of $4 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense. |
at December 31 | 2018 | 2017 | ||
(millions of Canadian $, unless otherwise noted) | ||||
Notional amount | 31,000 (US 22,700) | 25,400 (US 20,200) | ||
Fair value | 31,700 (US 23,200) | 28,900 (US 23,100) |
TransCanada Consolidated financial statements 2018 | 175 |
2018 | 2017 | ||||||||||
at December 31 | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||
(millions of Canadian $) | |||||||||||
Long-term debt, including current portion1,2 (Note 17) | (39,971 | ) | (42,284 | ) | (34,741 | ) | (40,180 | ) | |||
Junior subordinated notes (Note 18) | (7,508 | ) | (6,665 | ) | (7,007 | ) | (7,233 | ) | |||
(47,479 | ) | (48,949 | ) | (41,748 | ) | (47,413 | ) |
1 | Long-term debt is recorded at amortized cost, except for US$750 million (2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value. |
2 | Net income in 2018 included unrealized losses of $2 million (2017 – gains of $4 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at December 31, 2018 (2017 – US$1.1 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. |
2018 | 2017 | ||||||||||
at December 31 | LMCI Restricted Investments | Other Restricted Investments1 | LMCI Restricted Investments | Other Restricted Investments1 | |||||||
(millions of Canadian $) | |||||||||||
Fair value of fixed income securities2 | |||||||||||
Fixed income securities (maturing within 1 year) | — | 22 | — | 23 | |||||||
Fixed income securities (maturing within 1-5 years) | — | 110 | — | 107 | |||||||
Fixed income securities (maturing within 5-10 years) | 140 | — | 14 | — | |||||||
Fixed income securities (maturing after 10 years) | 952 | — | 790 | — | |||||||
1,092 | 132 | 804 | 130 |
1 | Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. |
2 | Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet. |
2018 | 2017 | 2016 | |||||||||||||||
year ended December 31 (millions of Canadian $) | LMCI restricted investments1 | Other restricted investments | LMCI restricted investments1 | Other restricted investments | LMCI restricted investments1 | Other restricted investments | |||||||||||
Net unrealized gains/(losses) | 11 | — | (3 | ) | 1 | (28 | ) | (1 | ) | ||||||||
Net realized losses2 | (4 | ) | — | (1 | ) | — | — | — |
1 | Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. |
2 | The realized gains and losses on the sale of LMCI restricted investment securities are determined using the average cost basis. |
176 | TransCanada Consolidated financial statements 2018 |
at December 31, 2018 | Cash Flow Hedges | Fair Value Hedges | Net Investment Hedges | Held for Trading | Total Fair Value of Derivative Instruments1 | |||||||||
(millions of Canadian $) | ||||||||||||||
Other current assets (Note 7) | ||||||||||||||
Commodities2 | 1 | — | — | 716 | 717 | |||||||||
Foreign exchange | — | — | 16 | 1 | 17 | |||||||||
Interest rate | 3 | — | — | — | 3 | |||||||||
4 | — | 16 | 717 | 737 | ||||||||||
Intangible and other assets (Note 12) | ||||||||||||||
Commodities2 | 1 | — | — | 50 | 51 | |||||||||
Foreign exchange | — | — | 1 | — | 1 | |||||||||
Interest rate | 8 | 1 | — | — | 9 | |||||||||
9 | 1 | 1 | 50 | 61 | ||||||||||
Total Derivative Assets | 13 | 1 | 17 | 767 | 798 | |||||||||
Accounts payable and other (Note 14) | ||||||||||||||
Commodities2 | (4 | ) | — | — | (622 | ) | (626 | ) | ||||||
Foreign exchange | — | — | (105 | ) | (188 | ) | (293 | ) | ||||||
Interest rate | — | (3 | ) | — | — | (3 | ) | |||||||
(4 | ) | (3 | ) | (105 | ) | (810 | ) | (922 | ) | |||||
Other long-term liabilities (Note 15) | ||||||||||||||
Commodities2 | — | — | — | (28 | ) | (28 | ) | |||||||
Foreign exchange | — | — | (2 | ) | — | (2 | ) | |||||||
Interest rate | (11 | ) | (1 | ) | — | — | (12 | ) | ||||||
(11 | ) | (1 | ) | (2 | ) | (28 | ) | (42 | ) | |||||
Total Derivative Liabilities | (15 | ) | (4 | ) | (107 | ) | (838 | ) | (964 | ) | ||||
Total Derivatives | (2 | ) | (3 | ) | (90 | ) | (71 | ) | (166 | ) |
1 | Fair value equals carrying value. |
2 | Includes purchases and sales of power, natural gas and liquids. |
TransCanada Consolidated financial statements 2018 | 177 |
at December 31, 2017 | Cash Flow Hedges | Fair Value Hedges | Net Investment Hedges | Held for Trading | Total Fair Value of Derivative Instruments1 | |||||||||
(millions of Canadian $) | ||||||||||||||
Other current assets (Note 7) | ||||||||||||||
Commodities2 | 1 | — | — | 249 | 250 | |||||||||
Foreign exchange | — | — | 8 | 70 | 78 | |||||||||
Interest rate | 3 | — | — | 1 | 4 | |||||||||
4 | — | 8 | 320 | 332 | ||||||||||
Intangible and other assets (Note 12) | ||||||||||||||
Commodities2 | — | — | — | 69 | 69 | |||||||||
Interest rate | 4 | — | — | — | 4 | |||||||||
4 | — | — | 69 | 73 | ||||||||||
Total Derivative Assets | 8 | — | 8 | 389 | 405 | |||||||||
Accounts payable and other (Note 14) | ||||||||||||||
Commodities2 | (6 | ) | — | — | (208 | ) | (214 | ) | ||||||
Foreign exchange | — | — | (159 | ) | (10 | ) | (169 | ) | ||||||
Interest rate | — | (4 | ) | — | — | (4 | ) | |||||||
(6 | ) | (4 | ) | (159 | ) | (218 | ) | (387 | ) | |||||
Other long-term liabilities (Note 15) | ||||||||||||||
Commodities2 | (2 | ) | — | — | (26 | ) | (28 | ) | ||||||
Foreign exchange | — | — | (43 | ) | — | (43 | ) | |||||||
Interest rate | — | (1 | ) | — | — | (1 | ) | |||||||
(2 | ) | (1 | ) | (43 | ) | (26 | ) | (72 | ) | |||||
Total Derivative Liabilities | (8 | ) | (5 | ) | (202 | ) | (244 | ) | (459 | ) | ||||
Total Derivatives | — | (5 | ) | (194 | ) | 145 | (54 | ) |
1 | Fair value equals carrying value. |
2 | Includes purchases and sales of power, natural gas and liquids. |
at December 31 | Carrying amount | Fair value hedging adjustments1 | ||||||||||
(millions of Canadian $) | 2018 | 2017 | 2018 | 2017 | ||||||||
Current portion of long-term debt | (748 | ) | (688 | ) | 3 | 1 | ||||||
Long-term debt | (273 | ) | (685 | ) | — | 4 | ||||||
(1,021 | ) | (1,373 | ) | 3 | 5 |
1 | At December 31, 2018 and 2017, adjustments for discontinued hedging relationships included in these balances were nil. |
178 | TransCanada Consolidated financial statements 2018 |
at December 31, 2018 | Power | Natural Gas | Liquids | Foreign Exchange | Interest Rate | |||||||||
Purchases1 | 23,865 | 44 | 59 | — | — | |||||||||
Sales1 | 17,689 | 56 | 79 | — | — | |||||||||
Millions of U.S. dollars | — | — | — | 3,862 | 1,650 | |||||||||
Maturity dates | 2019-2023 | 2019-2027 | 2019 | 2019 | 2019-2030 |
1 | Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. |
at December 31, 2017 | Power | Natural Gas | Liquids | Foreign Exchange | Interest Rate | |||||||||
Purchases1 | 66,132 | 133 | 6 | — | — | |||||||||
Sales1 | 42,836 | 135 | 7 | — | — | |||||||||
Millions of U.S. dollars | — | — | — | 2,931 | 2,300 | |||||||||
Millions of Mexican pesos | — | — | — | 100 | — | |||||||||
Maturity dates | 2018-2022 | 2018-2021 | 2018 | 2018 | 2018-2022 |
1 | Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Derivative instruments held for trading1 | ||||||||
Amount of unrealized gains/(losses) in the year | ||||||||
Commodities2 | 28 | 62 | 123 | |||||
Foreign exchange | (248 | ) | 88 | 25 | ||||
Interest rate | — | (1 | ) | — | ||||
Amount of realized gains/(losses) in the year | ||||||||
Commodities | 351 | (107 | ) | (204 | ) | |||
Foreign exchange | (24 | ) | 18 | 62 | ||||
Interest rate | — | 1 | — | |||||
Derivative instruments in hedging relationships | ||||||||
Amount of realized (losses)/gains in the year | ||||||||
Commodities | (1 | ) | 23 | (167 | ) | |||
Foreign exchange | — | 5 | (101 | ) | ||||
Interest rate | (1 | ) | 1 | 4 |
1 | Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively. |
2 | In 2018 and 2017, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2016 – net loss of $42 million). |
TransCanada Consolidated financial statements 2018 | 179 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $, pre-tax) | ||||||||
Change in fair value of derivative instruments recognized in OCI1 | ||||||||
Commodities | (1 | ) | (1 | ) | 39 | |||
Interest rate | (13 | ) | 4 | 5 | ||||
(14 | ) | 3 | 44 |
1 | No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI. |
year ended December 31 | Revenues (Energy) | Interest Expense | ||||||||||||||
(millions of Canadian $) | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | ||||||||||
Total Amount Presented in the Consolidated Statement of Income | 2,124 | 3,593 | 4,206 | (2,265 | ) | (2,069 | ) | (1,998 | ) | |||||||
Fair Value Hedges | ||||||||||||||||
Interest rate contracts | ||||||||||||||||
Hedged items | — | — | — | (71 | ) | (74 | ) | (74 | ) | |||||||
Derivatives designated as hedging instruments | — | — | — | (4 | ) | 1 | 8 | |||||||||
Cash Flow Hedges | ||||||||||||||||
Reclassification of gains/(losses) on derivative instruments from AOCI to net income1,2 | ||||||||||||||||
Interest rate contracts | — | — | — | 22 | 17 | 14 | ||||||||||
Commodity contracts | 5 | (20 | ) | 57 | — | — | — |
1 | Refer to Note 22, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. |
2 | There are no amounts recognized in earnings that were excluded from effectiveness testing. |
180 | TransCanada Consolidated financial statements 2018 |
at December 31, 2018 | Gross Derivative Instruments | Amounts Available for Offset1 | Net Amounts | |||||
(millions of Canadian $) | ||||||||
Derivative – Asset | ||||||||
Commodities | 768 | (626 | ) | 142 | ||||
Foreign exchange | 18 | (18 | ) | — | ||||
Interest rate | 12 | (4 | ) | 8 | ||||
798 | (648 | ) | 150 | |||||
Derivative – Liability | ||||||||
Commodities | (654 | ) | 626 | (28 | ) | |||
Foreign exchange | (295 | ) | 18 | (277 | ) | |||
Interest rate | (15 | ) | 4 | (11 | ) | |||
(964 | ) | 648 | (316 | ) |
1 | Amounts available for offset do not include cash collateral pledged or received. |
at December 31, 2017 | Gross Derivative Instruments | Amounts Available for Offset1 | Net Amounts | |||||
(millions of Canadian $) | ||||||||
Derivative – Asset | ||||||||
Commodities | 319 | (198 | ) | 121 | ||||
Foreign exchange | 78 | (56 | ) | 22 | ||||
Interest rate | 8 | (1 | ) | 7 | ||||
405 | (255 | ) | 150 | |||||
Derivative – Liability | ||||||||
Commodities | (242 | ) | 198 | (44 | ) | |||
Foreign exchange | (212 | ) | 56 | (156 | ) | |||
Interest rate | (5 | ) | 1 | (4 | ) | |||
(459 | ) | 255 | (204 | ) |
1 | Amounts available for offset do not include cash collateral pledged or received. |
TransCanada Consolidated financial statements 2018 | 181 |
Levels | How fair value has been determined |
Level I | Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis. |
Level II | Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances. |
Level III | Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II. |
182 | TransCanada Consolidated financial statements 2018 |
at December 31, 2018 | Quoted Prices in Active Markets (Level I)1 | Significant Other Observable Inputs (Level II)1 | Significant Unobservable Inputs (Level III)1 | Total | |||||||
(millions of Canadian $) | |||||||||||
Derivative Instrument Assets: | |||||||||||
Commodities | 581 | 187 | — | 768 | |||||||
Foreign exchange | — | 18 | — | 18 | |||||||
Interest rate | — | 12 | — | 12 | |||||||
Derivative Instrument Liabilities: | |||||||||||
Commodities | (555 | ) | (95 | ) | (4 | ) | (654 | ) | |||
Foreign exchange | — | (295 | ) | — | (295 | ) | |||||
Interest rate | — | (15 | ) | — | (15 | ) | |||||
26 | (188 | ) | (4 | ) | (166 | ) |
1 | There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2018. |
at December 31, 2017 | Quoted Prices in Active Markets (Level I)1 | Significant Other Observable Inputs (Level II)1 | Significant Unobservable Inputs (Level III)1 | Total | |||||||
(millions of Canadian $) | |||||||||||
Derivative Instrument Assets: | |||||||||||
Commodities | 21 | 283 | 15 | 319 | |||||||
Foreign exchange | — | 78 | — | 78 | |||||||
Interest rate | — | 8 | — | 8 | |||||||
Derivative Instrument Liabilities: | |||||||||||
Commodities | (27 | ) | (193 | ) | (22 | ) | (242 | ) | |||
Foreign exchange | — | (212 | ) | — | (212 | ) | |||||
Interest rate | — | (5 | ) | — | (5 | ) | |||||
(6 | ) | (41 | ) | (7 | ) | (54 | ) |
1 | There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2017. |
(millions of Canadian $, pre-tax) | 2018 | 2017 | |||
Balance at beginning of year | (7 | ) | 16 | ||
Transfers out of Level III | 5 | (19 | ) | ||
Total gains/(losses) included in Net income | 8 | (17 | ) | ||
Settlements | (9 | ) | 18 | ||
Sales | — | (5 | ) | ||
Foreign exchange | (1 | ) | — | ||
Balance at end of year1 | (4 | ) | (7 | ) |
1 | Revenues include unrealized losses of $5 million attributed to derivatives in the Level III category that were still held at December 31, 2018 (2017 – unrealized losses of $7 million). |
TransCanada Consolidated financial statements 2018 | 183 |
year ended December 31 | 2018 | 2017 | 2016 | |||||
(millions of Canadian $) | ||||||||
Increase in Accounts receivable | (69 | ) | (576 | ) | (482 | ) | ||
Increase in Inventories | (49 | ) | (38 | ) | (87 | ) | ||
Decrease/(increase) in Assets held for sale | — | 14 | (13 | ) | ||||
Decrease in Other current assets | 45 | 189 | 328 | |||||
(Decrease)/increase in Accounts payable and other | (70 | ) | 151 | 424 | ||||
Increase in Accrued interest | 41 | 12 | 62 | |||||
(Decrease)/increase in Liabilities related to assets held for sale | — | (25 | ) | 16 | ||||
(Increase)/decrease in Operating Working Capital | (102 | ) | (273 | ) | 248 |
184 | TransCanada Consolidated financial statements 2018 |
July 1, 2016 | ||||||
(millions of $) | U.S. | Canadian1 | ||||
Purchase Price Consideration | 10,294 | 13,392 | ||||
Fair Value | ||||||
Current assets | 658 | 856 | ||||
Plant, property and equipment | 7,560 | 9,835 | ||||
Equity investments | 441 | 574 | ||||
Regulatory assets | 190 | 248 | ||||
Intangible and other assets | 135 | 175 | ||||
Current liabilities | (597 | ) | (777 | ) | ||
Regulatory liabilities | (294 | ) | (383 | ) | ||
Other long-term liabilities | (144 | ) | (187 | ) | ||
Deferred income tax liabilities | (1,613 | ) | (2,098 | ) | ||
Long-term debt | (2,981 | ) | (3,878 | ) | ||
Non-controlling interests | (808 | ) | (1,051 | ) | ||
Fair Value of Net Assets Acquired | 2,547 | 3,314 | ||||
Goodwill | 7,747 | 10,078 |
1 | At July 1, 2016 exchange rate of $1.30. |
(millions of $) | Maturity Date | Type | Fair Value | Interest Rate | ||||||
COLUMBIA PIPELINE GROUP, INC. | ||||||||||
June 2018 | Senior Unsecured Notes (US$500) | US$506 | 2.45 | % | ||||||
June 2020 | Senior Unsecured Notes (US$750) | US$779 | 3.30 | % | ||||||
June 2025 | Senior Unsecured Notes (US$1,000) | US$1,092 | 4.50 | % | ||||||
June 2045 | Senior Unsecured Notes (US$500) | US$604 | 5.80 | % | ||||||
US$2,981 |
TransCanada Consolidated financial statements 2018 | 185 |
year ended December 31 | |||||||
(millions of Canadian $) | 2016 | 2015 | |||||
Revenues | 13,404 | 13,007 | |||||
Net Income/(Loss) | 627 | (820 | ) | ||||
Net Income/(Loss) Attributable to Common Shares | 234 | (971 | ) |
186 | TransCanada Consolidated financial statements 2018 |
year ended December 31 | Minimum Lease Payments | Amounts Recoverable under Subleases | Net Payments | |||||
(millions of Canadian $) | ||||||||
2019 | 81 | 7 | 74 | |||||
2020 | 78 | 7 | 71 | |||||
2021 | 76 | 4 | 72 | |||||
2022 | 69 | 3 | 66 | |||||
2023 | 67 | 3 | 64 | |||||
2024 and thereafter | 390 | 8 | 382 | |||||
761 | 32 | 729 |
• | approximately $4.6 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with the construction of the Coastal GasLink and NGTL System pipeline projects |
• | approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with Columbia Gas and Columbia Gulf growth projects |
• | approximately $0.3 billion for its Mexico natural gas pipelines, primarily related to construction of the Sur de Texas, Villa de Reyes and Tula pipeline projects |
• | approximately $0.4 billion for its Liquids pipelines, primarily related to the development of Keystone XL and construction of White Spruce |
• | approximately $0.7 billion for its Energy business, primarily related to its proportionate share of commitments for Bruce Power's life extension program |
• | approximately $0.1 billion for its Corporate segment related to various information technology services agreements. |
TransCanada Consolidated financial statements 2018 | 187 |
2018 | 2017 | ||||||||||||
at December 31 | Term | Potential Exposure1 | Carrying Value | Potential Exposure1 | Carrying Value | ||||||||
(millions of Canadian $) | |||||||||||||
Sur de Texas | ranging to 2020 | 183 | 1 | 315 | 2 | ||||||||
Bruce Power | ranging to 2021 | 88 | — | 88 | 1 | ||||||||
Other jointly owned entities | ranging to 2059 | 104 | 11 | 104 | 13 | ||||||||
375 | 12 | 507 | 16 |
1 | TransCanada's share of the potential estimated current or contingent exposure. |
188 | TransCanada Consolidated financial statements 2018 |
(millions of Canadian $) | Employee Severance | Lease Commitments | Total | ||||||
Restructuring liability as at December 31, 2016 | 36 | 63 | 99 | ||||||
Restructuring charges1 | — | 6 | 6 | ||||||
Accretion expense | — | 1 | 1 | ||||||
Cash payments | (27 | ) | (17 | ) | (44 | ) | |||
Restructuring liability as at December 31, 2017 | 9 | 53 | 62 | ||||||
Restructuring charges1 | — | 42 | 42 | ||||||
Accretion expense | — | 1 | 1 | ||||||
Cash payments | (9 | ) | (15 | ) | (24 | ) | |||
Restructuring Liability as at December 31, 2018 | — | 81 | 81 |
1 | At December 31, 2018, the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods (2017 – $3 million and $3 million, respectively). |
TransCanada Consolidated financial statements 2018 | 189 |
at December 31 | |||||||
(millions of Canadian $) | 2018 | 2017 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | 45 | 41 | |||||
Accounts receivable | 79 | 63 | |||||
Inventories | 24 | 23 | |||||
Other | 13 | 11 | |||||
161 | 138 | ||||||
Plant, Property and Equipment | 3,026 | 3,535 | |||||
Equity Investments | 965 | 917 | |||||
Goodwill | 453 | 490 | |||||
Intangible and Other Assets | 8 | 3 | |||||
4,613 | 5,083 | ||||||
LIABILITIES | |||||||
Current Liabilities | |||||||
Accounts payable and other | 88 | 137 | |||||
Dividends payable | — | 1 | |||||
Accrued interest | 24 | 23 | |||||
Current portion of long-term debt | 79 | 88 | |||||
191 | 249 | ||||||
Regulatory Liabilities | 43 | 34 | |||||
Other Long-Term Liabilities | 3 | 3 | |||||
Deferred Income Tax Liabilities | 13 | 13 | |||||
Long-Term Debt | 3,125 | 3,244 | |||||
3,375 | 3,543 |
at December 31 | |||||||
(millions of Canadian $) | 2018 | 2017 | |||||
Balance sheet | |||||||
Equity investments | 4,575 | 4,372 | |||||
Off-balance sheet | |||||||
Potential exposure to guarantees | 170 | 171 | |||||
Maximum exposure to loss | 4,745 | 4,543 |
190 | TransCanada Consolidated financial statements 2018 |
1. | I have reviewed this annual report on Form 40-F of TransCanada Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. |
5. | The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. |
/s/ RUSSELL K. GIRLING | |
Russell K. Girling President and Chief Executive Officer |
1. | I have reviewed this annual report on Form 40-F of TransCanada PipeLines Limited; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. |
5. | The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. |
/s/ RUSSELL K. GIRLING | |
Russell K. Girling President and Chief Executive Officer |
1. | I have reviewed this annual report on Form 40-F of TransCanada Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. |
5. | The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. |
/s/ DONALD R. MARCHAND | |
Donald R. Marchand Executive Vice-President and Chief Financial Officer |
1. | I have reviewed this annual report on Form 40-F of TransCanada PipeLines Limited; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting. |
5. | The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. |
/s/ DONALD R. MARCHAND | |
Donald R. Marchand Executive Vice-President and Chief Financial Officer |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ RUSSELL K. GIRLING | |
Russell K. Girling Chief Executive Officer | |
February 14, 2019 |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ RUSSELL K. GIRLING | |
Russell K. Girling Chief Executive Officer | |
February 14, 2019 |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ DONALD R. MARCHAND | |
Donald R. Marchand Chief Financial Officer | |
February 14, 2019 |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ DONALD R. MARCHAND | |
Donald R. Marchand Chief Financial Officer | |
February 14, 2019 |
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